Revisions to the Definitions and the Continuous Emission Monitoring Provisions of the Acid Rain Program and the NOX Budget Trading Program


[Federal Register: June 12, 2002 (Volume 67, Number 113)]
[Rules and Regulations]
[Page 40393-40476]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr12jn02-18]

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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72 and 75
[FRL-7207-4]
RIN 2060-AJ43
 
Revisions to the Definitions and the Continuous Emission 
Monitoring Provisions of the Acid Rain Program and the NOX Budget 
Trading Program

AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.

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SUMMARY: In this action, EPA is taking final action on the portions of 
the June 13, 2001 proposed rule revisions that modify the existing 
requirements for sources affected by the Acid Rain Program and by the 
NO_X Budget Trading Program under the October 27, 1998 
NO_X SIP Call. Certain changes to the proposed rule revisions 
have been made based on the public comments received. EPA is not 
finalizing the proposed changes at this time to the Appeal Procedures 
or to the Findings of Significant Contribution and Rulemaking on 
Section 126 Petitions for Purposes of Reducing Interstate Ozone 
Transport. Today's final rule establishes additional flexibility and 
options for sources in meeting the continuous emission monitoring 
system (CEMS) requirements under programs to reduce sulfur dioxide and 
nitrogen oxides emissions. These revisions may apply to sources that 
monitor and report emissions only during the ozone season, as well as 
to sources that monitor and report emissions for the entire year. The 
provisions in this final rule benefit the environment by ensuring that 
sulfur dioxide (S0₂), nitrogen oxides (NO_X), and 
carbon dioxide (CO₂) emissions are accurately monitored and 
reported, even as they benefit the affected industrial sources by 
creating opportunities to adopt cost saving procedures.

DATES: The effective date of this rule is July 12, 2002. However, 
regulated entities will have additional time to implement certain 
requirements, as described in Section V, Rule Implementation, and in 
the rule.

ADDRESSES: Docket. Supporting information, including public comments, 
used in developing the regulations is contained in Docket No. 
A-2000-33. This docket is available for public inspection 
and photocopying between 8:00 a.m. and 5:30 p.m. Monday through Friday, 
excluding government holidays, and is located at: EPA Air Docket (MC 
6102), Room M-1500, Waterside Mall, 401 M Street, SW, Washington, 
DC 20460. A reasonable fee may be charged for photocopying.

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

SUPPLEMENTARY INFORMATION: A redline/strikeout version of 40 CFR parts 
72 and 75 as amended by this final 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 Final Rule
III. Statutory Authority, Regulatory History, and Stakeholder 
Involvement
IV. Summary of Major Comments and Responses
    A. Missing Data
    1. What changes to the CEMS missing data procedures of 
Sec. 75.31 through 75.37 are finalized?
    2. How are the CEMS missing data provisions of subpart H 
affected by today's rule?
    3. What CEMS missing data provisions are finalized for units 
that do not produce electrical or thermal output?
    4. Will today's rule affect the way in which load ranges (or 
"bins") are established for missing data purposes?
    B. Low Mass Emissions Units
    1. Does today's rule change the qualification requirements for 
low mass emissions units?
    2. How does today's rule change the certification application 
procedures and requirements for low mass emissions units?
    3. How will today's rule affect the way in which fuel- and unit-
specific NO_X emission rates are determined for low mass 
emissions units?
    4. Does today's rule allow testing to be done at fewer than four 
load levels to determine fuel- and unit-specific NO_X 
emission rates for low mass emissions units?
    C. Quality Assurance/Quality Control
    1. What changes to the method of determining the NO_X 
MPC, MEC, span, and range are finalized in today's rule?
    2. What changes to the 7-day calibration error test are 
finalized?
    3. What changes to the QA/QC requirements for low-emitting 
sources are finalized?
    4. What changes to the stack flow-to-load ratio test are 
finalized?
    5. What special QA provisions are finalized for units that do 
not produce electrical output or steam load?
    D. Appendix D
    1. What changes to the definitions of "pipeline natural 
gas" and "natural gas" are finalized?
    2. How does today's rule change the method by which a gaseous 
fuel qualified as "pipeline natural gas" or 
"natural gas"?
    3. How does today's rule change the fuel sampling and data 
reporting requirements for gaseous fuels other than pipeline natural 
gas and natural gas?
    4. What changes to the appendix D missing data procedures are 
finalized?
    E. Other Highlights and Changes
    1. What changes to the compliance dates and timelines for 
monitor certification in Sec. 75.4 are finalized in today's 
rule?
    2. Does today's rule change the way in which unit and stack 
operating hours are counted?
    3. Does today's rule change the notification requirements for 
monitor certifications and recertifications?
    4. Does today's rule affect the way in which emissions are 
monitored and reported for units with bypass stacks?
    5. What other noteworthy provisions are finalized in today's 
rule?
    F. Streamlining Changes
V. Rule Implementation
VI. Administrative Requirements
    A. Executive Order 12866: Regulatory Planning and Review
    B. Unfunded Mandates Reform Act
    C. Paperwork Reduction Act
    D. Regulatory Flexibility Act
    E. National Technology Transfer and Advancement Act
    F. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    G. Executive Order 13132: Federalism
    H. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. Congressional Review Act

I. Regulated Entities

    Entities regulated by this action are fossil fuel-fired boilers, 
turbines, and combined cycle units that serve electric generators, 
produce steam, or cogenerate electricity and steam. While part 75 of 
title 40 of the Code of Federal Regulations (40 CFR) primarily 
regulates the electric utility industry, certain State and Federal 
NO_X mass emissions programs also rely on 40 CFR part 75 
(subpart H), and those programs may include boilers, turbines, and 
combined cycle units from other industries. Regulated categories and 
entities include:

------------------------------------------------------------------------
             Category                  Examples of Regulated 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

[[Page 40395]]

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, or organization is regulated by this 
action, you should carefully examine the applicability provisions in 40 
CFR 72.6, 72.7, and 72.8 and 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 Final Rule

    Today's action modifies existing monitoring and reporting 
requirements in 40 CFR parts 72 and 75. These requirements support 
emission control programs that use the monitoring and reporting 
provisions of part 75, such as the Acid Rain Program, and the 
NO_X Budget Trading Program developed under the October 27, 
1998, NO_X 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 changes finalized are as follows: 
the definitions of "pipeline natural gas" and 
"natural gas" in Sec. 72.2 are finalized as 
proposed to remove all references to the H₂S content of the 
fuel and instead be based on total sulfur content, along with 
corresponding changes appendix D to part 75; the low mass emissions 
(LME) units provisions in Sec. 75.19 are clarified and expanded 
and, for units with certain types of NO_X emission controls, 
qualification as a LME unit is made easier; the CEMS missing data 
procedures are revised to allow fuel-specific missing data 
substitution; the missing data procedures in subpart H of part 75 are 
expanded and clarified for sources that are non-load based and/or 
report emission data only in the ozone season; the NO_X span 
and range provisions in appendix A are revised to make them easier to 
implement for combustion turbines; and the alternate calibration error 
limit for daily operation is changed from 10 ppm to 5 ppm for units 
with span values of 50 ppm or less.
    EPA has developed a Response to Comment document (see Docket No. 
A-2000-33, Item V-C-1) as a supplement to this 
preamble, which addresses all the comments received on the proposed 
rule revisions. Comments that were raised and are not addressed in this 
preamble are responded to in this supplemental document.

III. Statutory Authority, Regulatory History, and Stakeholder 
Involvement

    In accordance with titles I and IV of the Clean Air Act (CAA, or 
the Act), with today's action EPA is promulgating revisions to rules 
implementing programs that the Agency has established to mitigate 
interstate transport of nitrogen oxides, as well as to reduce the 
acidic deposition precursor emissions of sulfur dioxide and nitrogen 
oxides. EPA originally promulgated 40 CFR parts 72 and 75 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 CEMS requirements in part 75 and relevant definitions in part 
72 (see below).
    Section 110 of the Act requires that State Implementation Plans 
(SIPs) prohibit sources from contributing significantly to 
nonattainment or maintenance of attainment in another State. On October 
27, 1998, EPA issued the NO_X SIP Call, a final rule under 
section 110 requiring certain States to revise their SIPs to meet 
NO_X emission budgets to prevent such significant 
contribution to ozone nonattainment. States may adopt in their SIPs a 
NO_X Budget Trading Program for large electric generating 
units (EGUs) and large non-electric generating units (non-EGUs) and 
require such units to monitor under part 75. Further, section 126 of 
the Act authorizes EPA to directly regulate, and require reductions of 
NO_X emissions from, sources that emit in violation of the 
prohibition in section 110 against significantly contributing to ozone 
nonattainment or maintenance problems in a downwind State. On January 
18, 2000, EPA published a finding that large EGUs and certain large 
non-EGUs in particular States named in petitions filed by several 
northeastern States emit NO_X in violation of Section 126 of 
the CAA (65 FR 2674). In that same notice, the EPA finalized the 
Federal NO_X Budget Trading Program in part 97 as the control 
remedy and required that these units monitor under part 75.
    In today's rule, the provisions of parts 72 and 75 are revised to 
modify the requirements for sources under the Acid Rain Program, the 
NO_X SIP Call, and the Federal NO_X Budget Trading 
Program.
    As noted above, the Agency first promulgated parts 72 and 75 under 
title IV on January 11, 1993. On May 17, 1995 and November 20, 1996, 
the Agency revised parts 72 and 75 to make implementation simpler (60 
FR 26510 and 61 FR 59142). On May 21, 1998, the Agency proposed 
additional revisions to parts 72 and 75 to make implementation easier 
and more efficient, to improve quality assurance requirements, and to 
create new alternative monitoring options (63 FR 28032). EPA 
promulgated final rule revisions addressing some of these additional 
proposed revisions, based on comments received, when EPA promulgated 
the NO_X SIP Call (63 FR 57356). On May 26, 1999, EPA issued 
final rule revisions addressing the remaining May 21, 1998 proposed 
revisions (64 FR 28564). On June 13, 2001, EPA proposed further 
revisions to parts 72, 75, 78, and 97 (66 FR 31978). The revisions to 
parts 72 and 75 are being finalized in today's rule, while the changes 
to parts 78 and 97 will be addressed in a later rulemaking.
    Throughout the implementation of the Acid Rain Program, 
particularly since 1995, EPA has worked and continues to work on a 
regular basis with stakeholders, the regulated community, the public, 
other state and local agencies, and environmental groups and 
consultants. Internally, EPA holds frequent policy meetings to discuss 
many of the questions and problems that affected sources raise to their 
Regional contact in EPA. Many of the changes in today's rule result 
from industry petitions to the Agency as well as comments, phone calls, 
and dialogues during conferences and workshops. Most recently, EPA 
conducted two conferences in July (Louisville, KY) and September 
(Alexandria, VA) of 2001, and then initiated five regional workshops 
targeted at the regulated community and state agencies to support the 
Acid Rain Program and assist in implementing the NO_X Budget 
Trading Program. EPA is committed to this ongoing interaction with 
stakeholders across all spectra.

IV. Summary of Major Comments and Responses

    EPA responded to all comments received by the close of the extended 
comment period, August 20, 2001, regarding the current proposal. EPA's 
responses are summarized in this section of the preamble and are 
available in their entirety in the Response to Comment document in the 
rule docket (see Docket No. A-2000-33, Item 
V-C-1). The majority of comments related to parts 72 and 
75; therefore, this section addresses those issues. Revisions to part 
78 received no comments, and revisions to part 97 received only two 
comments, both of which are addressed in the Response to

[[Page 40396]]

Comment document. As noted above, EPA intends to finalize changes to 
part 78 and 97 in a separate rulemaking. The major topics in part 75 
that EPA is focusing on in this section are: missing data; LME units; 
quality assurance and quality control (QA/QC); appendix D; other 
highlights and changes; and streamlining changes.

A. Missing Data

1. What Changes to the CEMS Missing Data Procedures of 
Sec. 75.31 Through 75.37 Are Finalized?
Background
a. What is Currently Required?
    The part 75 CEMS missing data procedures in 
Sec. 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.
    Existing 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 (e.g., SO₂, NO_X, flow rate) 
in order to provide substitute data values when a historical lookback 
is required.
    For units with add-on SO₂ or NO_X emission 
controls, Sec. 75.34 allows two principal missing data options. 
The owner or operator may either: (1) Report maximum potential values 
or, if the controls are documented to be operating properly, report the 
standard missing data procedures; or (2) petition the Administrator to 
develop and use site-specific parametric monitoring procedures for 
missing data substitution in lieu of using the standard missing data 
procedures. Section 75.34(a)(2) also allows the owner or operator to 
petition the Administrator for permission to report the maximum 
controlled emission rate recorded in the previous 720 quality-assured 
monitor operating hours (without regard to control operational status), 
in cases where the standard missing data routines would require the 
maximum value in the lookback period to be reported.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise the part 75 missing data 
procedures to allow the standard missing data substitution in 
Sec. 75.33 to be done on a fuel-specific basis. The proposed 
revisions would allow the owner or operator to create and maintain 
separate databases for missing data purposes for each type of fuel 
combusted in the unit. Substitute data values would be derived from the 
appropriate database, depending on the type of fuel being burned during 
the missing data period.
    For units with add-on SO₂ or NO_X emission 
controls, EPA further proposed to remove the petition provision from 
Sec. 75.34(a)(2) and replace it with a new missing data option, 
based on the operating status of the emission controls. The owner or 
operator of a unit with add-on SO₂ or NO_X 
emission controls would be allowed to create and maintain two separate 
databases, controlled and uncontrolled, for missing data purposes. Any 
hour in which the add-on controls were documented to be operating 
(i.e., on) would be included in the controlled database. Any hour in 
which the controls were not operating (i.e., off) would be included in 
the uncontrolled database. The appropriate substitute data value for 
each hour of a missing data period would be taken from either the 
controlled or uncontrolled database, depending on whether the emission 
controls were documented (by means of parametric data) to be operating 
properly during the hour.
    EPA also proposed to change the way in which parametric data are 
used to document proper operation of add-on emission controls during 
periods of missing SO₂ or NO_X data. 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 a minimum of 720 hours of parametric 
data recorded during unit operation, when the add-on controls are in-
service and the SO₂ or NO_X monitor at the control 
device outlet is providing quality-assured data. 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 SO₂ or NO_X 
data.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the fuel-specific missing data option, with 
some editorial changes including new language addressing the co-firing 
of fuels (see Discussion, below). However, based on comments received, 
EPA is not adopting the other proposed missing data option, which would 
have allowed the owners or operators of units with add-on emission 
controls to separate their data into controlled and uncontrolled 
databases. The final rule replaces, in response to these comments, the 
proposed option with a provision that accomplishes a similar objective 
with respect to seasonally operated control devices, without requiring 
control device operational status to be documented. The replacement 
provision allows subpart H sources that report data on a year-round 
basis to separate their quality-assured NO_X emission data 
into ozone season data and non-ozone season data for missing data 
purposes. The final rule also retains the provision in 
Sec. 75.34 which allows sources to petition to report the 
maximum controlled emission rate in a 720-hour lookback period.
Discussion
    Two commenters were supportive of the proposed fuel-specific 
missing data option (Utility Air Regulatory Group (UARG); Clean Energy 
Group). However, another commenter asked EPA to explain what it means 
to create and maintain a "separate database" for each fuel 
or blend, and also asked how a "blend" is determined 
(KVB-Enertec (KVB)). Two commenters questioned how these proposed 
missing data procedures would be implemented for units that sometimes 
co-fire different types of fuel (UARG, KVB). Specifically, the 
commenters expressed concern about having to maintain an extra database 
for co-fired hours. One of the commenters suggested keeping only 
single-fuel databases and pro-rating the missing data values during co-
fired hours (UARG).
    Based on these comments, EPA incorporates the fuel-specific missing 
data option into today's rule, although the final rule language is 
somewhat modified from the proposal. The final rule differs from the 
proposal in that it provides for greater flexibility in how to 
implement the new missing data option. Paragraphs (b)(6) and (c)(8) in 
Sec. 75.33 give more general implementation guidelines, rather 
than providing detailed instructions. Regarding the comments about co-
firing, while EPA agrees that it is desirable to maintain as few 
databases as possible, the Agency did not incorporate the commenter's 
suggested approach because the commenter did not provide an adequate 
explanation of how it would work. However, today's rule provides an 
alternative to maintaining separate databases for co-fired hours for 
units that co-fire fuels and elect to use the fuel-specific missing 
data option. The final rule allows the owner or operator to keep 
single-fuel databases, provided

[[Page 40397]]

that the database for the fuel with the higher emission rate is used to 
provide substitute data values during co-fired hours.
    Regarding the Agency's proposal to provide a control status-
specific missing data option for units with add-on SO₂ and 
NO_X emission controls, two commenters supported the concept 
of this option (UARG, Clean Energy Group). However, strenuous 
objections were raised to the proposed method of documenting proper 
operation of the add-on controls (UARG; Robert Machaver (Machaver)). In 
particular, the commenters objected to the potential high cost of 
developing complex correlations between parametric data and control 
device removal efficiency and questioned the usefulness and reliability 
of such correlations. One commenter also objected to removing the 
petition provision from Sec. 75.34(a)(2), which would allow the 
source to report the maximum controlled value in a 720-hour lookback 
period (UARG).
    After careful consideration of the comments, EPA replaces the 
proposed missing data option with a procedure that will achieve the 
objective of the proposal for seasonally operated controls, without 
being dependent on the operational status of the add-on emission 
controls. The Agency also is not adopting the requirement to develop a 
correlation between control device removal efficiency and parametric 
data to demonstrate proper operation of the add-on emission controls, 
principally in response to the objections of the commenters to the cost 
and level of effort needed to develop correlations between parametric 
data and control device removal efficiency. The original rule language 
in Sec. 75.34(d) is retained, requiring sources to specify in 
the quality assurance (QA) plan for the unit the essential parameters 
and ranges needed to verify proper operation of the add-on emission 
controls.
    It should be noted that one of the principal reasons EPA proposed 
the control status-specific missing data option in 
Sec. 75.34(a)(2) for units with add-on emission controls was to 
accommodate units that are subject to the Federal NO_X Budget 
Trading Program (which is being implemented as a result of the 
NO_X SIP Call). In particular, many units required to report 
NO_X emissions data on a year-round basis will operate their 
add-on NO_X emission controls only during the ozone season, 
in order to comply with the NO_X emission reduction 
requirements of the NO_X SIP Call. The proposed missing data 
option would have allowed these sources to separate their uncontrolled 
and controlled emission data, thereby providing a more equitable scheme 
for missing data substitution.
    After further consideration, taking into account the supportive 
comments for the concept of the proposed missing data option, EPA 
believes that the objective of the option can be accomplished in a 
different way, without requiring separate controlled and uncontrolled 
databases to be maintained or that any parametric correlations be 
developed. Accordingly, Sec. 75.34(a)(2) of today's rule allows 
the owner or operator to separate the historical, quality-assured 
NO_X emissions data into ozone season and non-ozone season 
NO_X data, for missing data purposes. Use of this missing 
data option is limited to units that report NO_X mass 
emissions data on a year-round basis under subpart H of part 75, and 
that operate their NO_X emission controls only during the 
ozone season, or in a less efficient manner outside the ozone season. 
During periods of NO_X missing data, revised 
Sec. 75.34(a)(2) specifies that the appropriate substitute data 
values are to be drawn from one database or the other, depending on 
whether the missing data period is inside or outside the ozone season. 
Missing data periods that begin outside the ozone season and continue 
into the ozone season are treated as two separate missing data 
incidents, one ending on April 30, hour 23, and one beginning on May 1, 
hour 00. Further, the standard NO_X missing data algorithms 
may be applied at all times during the non-ozone season missing data 
periods, without any requirement to record parametric data to verify 
proper operation of add-on controls.
2. How Are the CEMS Missing Data Provisions of Subpart H Affected by 
Today's Rule?
Background
a. What Is Currently Required?
    The missing data procedures for units which are subject to a State 
or Federal NO_X mass emissions reduction program and must 
monitor NO_X mass emissions according to subpart H of part 75 
are specified in Sec. 75.70(f) and 75.74(c)(7). Section 
75.70(f) requires the initial and standard missing data procedures of 
Sec. 75.31 through 75.37 to be used for sources that 
report emission data on a year-round basis. Section 75.74(c)(7) 
requires subpart H sources that report data on an ozone season-only 
basis to use the missing data procedures of Sec. 75.31 
through 75.37 also, except that only data from within the ozone season 
are to be used in the historical lookbacks.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise Sec. 75.74(c)(7) 
by adding a new paragraph (iii), with subparagraphs (A) through (M), 
explaining how to apply the part 75 missing data procedures in 
Sec. 75.31 through 75.37 on an ozone season-only basis. 
EPA proposed 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. Thus, 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 include all of the quality-assured CEMS data that have 
been recorded throughout the year. Also, the percent monitor data 
availability (PMA) calculations described in Sec. 75.32, which 
are always based on a particular number of unit operating hours, 
include unit operating hours from all four calendar quarters of the 
year.
    Proposed Sec. 75.74(c)(7)(iii) would modify the initial and 
standard part 75 missing data procedures in Sec. 75.31 
through 75.37 to adapt them to sources that report emission data only 
during the ozone season. The missing data instructions for ozone 
season-only reporters were written in a parallel manner to the missing 
data procedures for year-round reporters.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the changes to Sec. 75.74(c)(7) as 
proposed, except that for both PMA calculations and historical missing 
data lookbacks, the lookback periods would be limited to three years 
(26,280 clock hours) prior to the missing data period, rather than 
three ozone seasons as proposed.
    EPA further notes that the fuel-specific missing data option 
described above in question 1 of this section is available to all 
subpart H sources, and the option to create and maintain separate ozone 
season and non-ozone season databases for missing data purposes is 
available to subpart H sources that report emissions data on a year-
round basis.
Discussion
    EPA received only one comment on the proposed missing data 
revisions to Sec. 75.74(c)(7). The commenter recommended that 
the lookback period be limited to three years prior to each missing 
data period rather than three ozone seasons as proposed (Environmental 
Systems Corporation (ESC)). Another commenter questioned similar 
language found in proposed

[[Page 40398]]

Sec. 75.33(c)(9), i.e., the parenthetical expression "(or 
three ozone seasons)" next to the words, "three 
years", referring to missing data lookbacks (Monitor Labs 
(Monitor)). EPA agrees with the commenters that for the purposes of 
missing data lookbacks, consistency is essential. For both year-round 
reporters and sources that report emissions on an ozone season-only 
basis, no data recorded more than three years prior to the missing data 
period should be used in the historical lookbacks. Therefore, in 
today's rule, all references in Sec. 75.33, 
Sec. 75.74(c)(7)(iii), and elsewhere to data recorded in the 
previous three ozone seasons are removed and replaced with references 
to the previous three years.
3. What CEMS Missing Data Provisions Are Finalized for Units That Do 
Not Produce Electrical or Thermal Output?
Background
    One of the main objectives of the June 13, 2001, proposed rule was 
to modify the existing monitoring and reporting sections of parts 72 
and 75 that apply to NO_X emission reduction programs, such 
as the Federal NO_X Budget Trading Program developed in 
response to the October 27, 1998 SIP call. Under the NO_X SIP 
call, States have the flexibility to include stationary sources other 
than EGUs in their NO_X reduction plans. Some of these non-
EGUs (such as cement kilns and refinery process heaters) do not produce 
electrical or thermal output, i.e., "load."
a. What Is Currently Required?
    EPA examined the part 75 missing data provisions to assess whether 
those provisions are adequate for determining NO_X mass 
emissions from non-EGUs. As a result of this assessment, EPA concluded 
that for industrial boilers which produce steam load and which are very 
similar to electric utility boilers, no significant changes to the 
missing data provisions of part 75 would be required. However, for 
cement kilns and refinery process heaters which do not produce 
electricity or steam load, EPA concluded that modifications to the 
missing data routines for NO_X concentration, NO_X 
emission rate, stack flow rate, and fuel flow rate would be necessary, 
since these missing data routines are load-dependent.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed non-load-based missing data routines 
which are modeled after, and are much the same as, the existing 
routines for load-based units, with one important difference: the owner 
or operator of a non-load-based unit would have a choice to define and 
use "operational bins" to segregate the quality-assured 
emissions data, or not to use operational bins at all.
    The reason EPA proposed allowing the use of operational bins was to 
give affected facilities the flexibility to customize their missing 
data routines, based on plant operational parameters and conditions 
that affect NO_X emissions, stack flow rate, or fuel flow 
rate. The procedures and requirements for defining operational bins 
were proposed as new sections 3 and 4 of appendix C to part 75. These 
new provisions would require the owner or operator to provide a 
complete description of each operational bin in the hardcopy portion of 
the monitoring plan and to monitor the operating conditions used to 
define the operational bin.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the missing data provisions for units that 
do not produce electrical or steam load. The final rule differs from 
the proposal in the following ways: (1) In Table 3, the algorithms 
requiring a comparison of the average value in a 2,160 lookback period 
against the 90th (or 95th) percentile value have been simplified to 
require that just the percentile value be reported (the reasons for 
this change are given in the Discussion immediately below); and (2) 
proposed section 4 of appendix C, which would have allowed the use of 
operational bins for fuel flow rate missing data, is not adopted (the 
reasons for not finalizing that option are explained in detail in the 
Discussion in Section IV. D.4. of this preamble).
Discussion
    EPA received comments on the proposed missing data provisions for 
non-load-based units from only two commenters (KVB; American Portland 
Cement Alliance (APCA)). The first commenter stated that the rule 
should provide a clear way of defining "operational bins" 
(KVB). The second commenter fully supported the proposed operational 
bin provisions, but objected to the use of 90th percentile, 95th 
percentile, and maximum values in the missing data lookback periods for 
NO_X and flow rate, claiming that these percentile values, 
which may be reasonable for EGUs, are unfairly punitive for the 
affected units in the commenter's industry (APCA). The second commenter 
included supplementary data previously presented to EPA in 1999 (see 
Docket No. A-2000-33, Item II-C-2) and proposed 
an alternate missing data protocol, using a "percent-above-
average" approach in lieu of using the 90th percentile, 95th 
percentile, and maximum values. The commenter asked EPA to revisit the 
Agency's prior data analysis, claiming that EPA's previous analysis had 
overstated the variability of EGU emission data by not taking certain 
factors into consideration. EPA declines to adopt the commenter's 
percent-above-average proposal, and concludes that no additional data 
analysis is necessary in order to support an appropriate missing data 
routine for non-load units.
    The most significant reason that EPA rejects the commenter's 
proposal is because the proposal rests on a fundamental 
misunderstanding of the basis and purpose of the missing data 
procedures. As stated in previous meetings and conversations with the 
commenter and in EPA's detailed written response, sent to the commenter 
on November 22, 2000 (see Docket No. A-2000-33, Item 
II-C-3), the key issue is the following: the missing data 
procedure in 40 CFR part 75 is designed to provide substitute values 
strictly relative to a unit's own emissions history, not compared to 
the emissions history of the universe of all units, as would be the 
case using the proposed percent-above-average multiplier.
    The missing data procedure strictly pertains to the monitoring of 
emissions, not to the operation of a unit. It implements Section 412(d) 
of the CAA which mandates EPA's Administrator to prescribe a means to 
calculate emission values during periods when data from the certified 
monitor is unavailable. The purpose is to substitute a value that is 
not lower than the unknown actual value for an improperly operated 
monitor. This means that a comparison of the variability of one unit's 
emission data to another unit's emission data (or to a class of other 
units' emission data), or a comparison of emission levels at one unit 
relative to another unit (or class of units), is not relevant in 
assessing the applicability of the missing data procedure. This can be 
seen both in the regulatory history and the structure of the missing 
data procedure.
    As stated in the preamble to the original 40 CFR part 75 
regulations published in the Federal Register on January 11, 1993 (58 
FR 3635), the primary intent in developing the missing data procedure 
was to provide a "substantial incentive to improve monitor 
availability" (58 FR 3637). To provide this substantial 
incentive, the Agency originally considered proposals to use only the 
maximum previous value recorded and the average of the five highest 
previously recorded values,

[[Page 40399]]

and finally settled on the current tiered approach. All of the 
approaches, contemplated and adopted, were premised on providing an 
incentive to keep monitors operational by requiring substitution of 
either the maximum value previously recorded at each specific facility 
or a value higher than at least 90 percent (for shorter monitor 
outages) or 95 percent (for longer monitor outages) of the values 
previously recorded at the specific unit. None of the approaches 
offered variations based on differences in emission variability or 
emission levels encountered at different units. To do so would have 
been contrary to the goal of providing, for each and every unit, a 
"substantial incentive to improve monitor availability" (58 
FR 3637, January 11, 1993).
    The commenter, on the other hand, proposes using a multiplier which 
is based on the averaged emissions history of a different set of units, 
that of utility units, which in aggregate would not display the high 
emissions excursions that are typical of cement kilns. The commenter 
does not dispute the need for a missing data procedure as an important 
component of a monitoring program; just its application during times of 
long monitor outage and low monitor availability exactly the 
times that the missing data routine was designed to limit. Their 
proposal suggests using the "percent above the average for each 
percentile as calculated from the electric utility boiler data to the 
cement kiln data." This proposal underscores the commenter's 
misunderstanding about the purpose of missing data.
    Use of the commenter's proposed percentage-above-average multiplier 
would mean that even in situations of substantial monitor outages 
(representing as much as 20 percent of a monitoring year), kilns whose 
own emission history displayed frequent excursions into high emission 
levels (as illustrated, for example, in commenter's Figure 1, page 2 of 
the attachment to Docket No. A-2000-33, Item 
IV-D-2) would substitute values substantially below these 
high excursions. The proposed procedure could have an effect completely 
contrary to the regulatory intent of the missing data procedure, i.e., 
providing an incentive to improve monitor availability. In fact, EPA 
believes this approach, were it to be employed, would cause a reverse 
incentive to turn off monitors at affected facilities. The commenter 
acknowledges that the NO_X emitted from their facilities is 
thermal NO_X, which is a critical aspect of the product's 
quality control. Because temperatures are product-related, they are 
carefully monitored. Operators may be able to predict, therefore, when 
emissions are high. Because of the market value of emissions, the 
percent-above-average multiplier approach may encourage sources to turn 
off monitors at higher fuel flow rates or higher kiln temperatures when 
NO_X emissions might increase. EPA experienced similar 
concerns with the utility industry in the early 1990s, when a diverse 
array of commenters recommended that EPA provide sufficiently punitive 
procedures to ensure that there would be an "effective deterrent 
to deliberate shutdowns of CEMS during period of high emissions' (58 FR 
3637, January 11, 1993). These concerns were a factor in the final 
approach that was adopted.
    The commenter's methodology is inconsistent with the purpose of 
missing data. The commenter misconstrues the concept of missing data 
substitution and its implementation by stating that missing data 
routines were created to encourage three activities: maintaining CEMS; 
getting malfunctioning CEMS back on line quickly; and operating power 
plants efficiently so as to avoid NO_X spikes. While the 
first two points are correct, the third "activity" has 
never been a purpose of missing data. Rather, it is a consequence of 
efficient plant operations which has some ancillary benefits. Operating 
bins, discussed later, afford similar benefits to kiln operators. In 
fact, there are numerous options available to kiln operators, as there 
are for EGUs, to minimize the need for and impacts of missing data 
routines. For instance, in the early years of monitoring, some 
utilities that were initially concerned about missing data protocols 
installed redundant backup systems so that if one monitor went down, 
another was available and no missing data period would be incurred. 
Others bought "like-kind replacement analyzers" that were 
also available should the primary monitor not perform. However, over 
time, many of these sources have found that these options were not 
necessary because, through proper maintenance of the CEMS, performance 
is usually not an issue. The commenter's analysis does not consider 
these options.
    The commenter also claims that "facilities with less reliable 
CEMS" need tailored missing data protocols "to represent 
the realities of cement manufacturing." EPA does not believe that 
this comment presents a relevant issue. The commenter has provided no 
evidence to demonstrate any basis for monitors to perform less reliably 
on cement kilns. The NO_X concentration monitor and stack 
flow monitor (critical CEMS components) that are installed on a cement 
kiln stack are no different from those that might be installed at a 
coal-fired utility boiler. APCA indicates that most of its companies 
burn coal as fuel in their cement making process. The result of burning 
coal, just like in a utility boiler, is a gas that exits the kiln 
through a stack. The CEMS samples that gas on minute-by-minute 
intervals in order to come up with a quality assured operating hour of 
data, which is banked in a data acquisition and handling system (DAHS). 
The only time the owner or operator of a cement kiln will have to use 
the missing data substitution protocol is when the CEMS is out of order 
or not operating properly. Utilities are currently maintaining CEMS at 
above 99 percent availability, up from around 95 percent when CEMS were 
first installed on utility boilers under the Acid Rain Program in the 
mid 1990s.
    The commenter has also suggested that the standard missing data 
procedure creates an equity issue, and that EPA is penalizing the 
cement industry unfairly because of its high variability. EPA disagrees 
with the commenter. EPA requires that all continuous emission monitors 
be continuously maintained and operated and has created an incentive 
structure, in the form of missing data procedures, to ensure this. 
Studies have demonstrated variability, comparable to that which APCA 
claims for cement kilns, for utility units in the pre- and post-control 
mode (see Docket No. A-92-15, Item II-I-26). 
EPA has demonstrated in previous data analyses and correspondence with 
the commenter (see Docket No. A-2000-33, Items 
II-C-2 and II-C-3) that there are many EGUs 
with variability of NO_X emission rate comparable to that for 
the cement kilns. EPA examined data from more than 1,000 utility 
boilers and compared it to the limited data submitted by the commenter 
for seven cement kilns out of the approximately 200 kilns operating in 
the U.S.. EPA's intent in performing the data analysis was to show 
that, even taken at face value, the commenter's contention is without 
merit: a statistical analysis of the data showed that there are EGUs 
with just as much emission rate variability (reflected as relative 
standard deviation). Consequently, EPA does not accept the premise of 
the commenter's concern.
    Further, it is important to note that many utilities have done an 
exceptional job, over time, of reducing emission variability. EPA would 
also note that the cement industry data analysis did not

[[Page 40400]]

reflect data stratification into operational bins. At the commenter's 
suggestion, EPA has proposed the use of "operational bins" 
which allow emissions data to be sub-categorized for missing data 
purposes (e.g., for mid-kiln injection of fuel, a bin for injection 
system on and a bin for injection system off). These operational bins 
are analogous to the load bins available to EGUs, and will allow non-
load units to avoid unnecessarily reporting the highest missing data 
value, if they can show that during the time CEMS are not operational 
the unit was in an operating bin for which a "lower" 
highest missing data value applies. The Agency is confident that 
application of the operating bin concept will reduce the conservatism 
of missing data procedures for kilns.
    The commenter also suggests that EPA's proposal to remove the hour 
before/hour after (HB/HA) algorithm from the missing data routine for 
non-load based units suggests that the Agency concedes that kilns are 
more variable than EGUs. To the contrary, the purpose of the HB/HA 
option, as applied to load based units, is to capture the fact that 
units may be operated for extended periods at peak load. In such a 
case, a unit at its maximum load and maximum emissions may actually 
have greater than the 95th percentile emissions (i.e., the 95th 
percentile may be too low a number under such conditions to substitute 
for the unknown value). So the HB/HA provision was developed to 
potentially capture such incidents by providing, during periods of long 
outages, a substitute value which is the greater of the HB/HA or the 
90th (or 95th) percentile in a 2,160 hour lookback period. Based on 
commenter-provided data for seven cement kilns, EPA initially suspected 
that short-term variability could cause the application of HB/HA to be 
punitive. However, although the Agency has concerns relating to the 
representation of industry data, we believe that there is little risk 
in deferring applicability of the provision until such time as 
sufficient information is available on an operating bin basis to assess 
the effectiveness of percentile based data substitution. EPA reserves 
the right to examine cement kiln data that is reported in the future 
and reconsider whether or not this decision is appropriate.
    As an alternative, in the June 13, 2001 proposed rule revisions, 
EPA proposed to replace the HB/HA criterion with the average value in a 
2,160-hour lookback period in the NO_X missing data 
algorithms in Table 3. The commenter has correctly pointed out in 
comments on the proposal that EPA's proposed replacement for the HB/HA 
criterion in Table 3 (i.e., comparison of the average in the 2,160 hour 
lookback period and 90th or 95th percentile value of the same set of 
data) is technically unsound. The proposed replacement algorithms that 
require the "higher of" the 90th (or 95th) percentile value 
or the average value to be reported are meaningless, since the 90th or 
95th percentile values will always be higher than the average for the 
same data set. Therefore, in the interest of regulatory clarification, 
Table 3 has been modified to eliminate the required comparison of 
averages and higher percentiles, simply leaving in place the percentile 
requirement.
    In view of the these considerations, in today's rule EPA finalizes 
the missing data provisions as proposed for both load-based and non-
load-based units, save for the revision to Table 3 that removes the 
requirement for the average versus percentile value comparisons.
4. Will Today's Rule Affect the Way in Which Load Ranges (or 
"Bins") Are Established for Missing Data Purposes?
Background
a. What Is Currently Required?
    Section 2 of appendix C to part 75 provides a procedure for 
establishing missing data load ranges ("bins") for 
NO_X emission rate, NO_X concentration, stack flow 
rate and fuel flow rate. The procedure consists of establishing 10 (or, 
in some cases, 20) load ranges, which are defined as percentages of the 
maximum hourly gross load of the unit.
b. What Changes Were Proposed?
    EPA proposed to revise section 2.2.1 of appendix C, particularly 
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. 
Having established the maximum hourly gross load, the missing data load 
ranges would then be determined as percentages of the MHGL.
c. What Changes Is EPA Finalizing?
    EPA is not adopting these proposed changes, based on the comments 
received. Today's final rule retains the existing text of section 2.2.1 
of appendix C.
Discussion
    EPA received significant adverse comments on the proposed changes 
to section 2.2.1 of appendix C. Two commenters objected to the proposed 
removal of the option to use hourly gross steam load to establish the 
load bins (UARG, Machaver). The commenters also raised technical 
questions and issues. Concerns were expressed that the proposed method 
of converting heat input to equivalent electrical output would 
underestimate the electrical output of the steam turbine for combined 
cycle units, and that the method does not provide a means of accounting 
for hourly load contributions from the duct burner during fuel flowrate 
missing data periods (UARG, Machaver). After consideration of these 
comments, EPA is not finalizing the proposed changes to section 2.2.1 
and retains the existing rule text.
B. Low Mass Emissions Units
1. Does Today's Rule Change the Qualification Requirements for Low Mass 
Emissions Units?
Background
a. What Is Currently Required?
    In October, 1998, EPA promulgated the low mass emissions (LME) 
methodology in Sec. 75.19, which provides certain qualifying 
units an alternative means of complying with part 75 without installing 
continuous monitoring systems. For an Acid Rain Program unit to qualify 
to use the LME methodology, Sec. 75.19(a) states that the unit 
must be oil- or gas-fired, combusting only natural gas or fuel oil, and 
must demonstrate that its emissions do not exceed 25 tons of 
SO₂ and 50 tons of NO_X per year. This 
demonstration must consider both actual (or projected) emissions and 
emissions calculated as set forth in Sec. 75.19. For a non-Acid 
Rain unit subject to a State or Federal NO_X emissions 
reduction program that adopts the monitoring provisions of subpart H of 
part 75, if the unit reports NO_X mass emission data only 
during the ozone season, Sec. 75.74(c)(10) states that the unit 
can qualify for LME status if it demonstrates that its emissions do not 
exceed 25 tons of NO_X per ozone season. The existing text of 
part 75 does not specify a LME NO_X emission

[[Page 40401]]

threshold for non-Acid Rain subpart H units that report emissions data 
on a year-round basis.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise paragraph (a) of 
Sec. 75.19 to more clearly state the LME applicability criteria 
for Acid Rain Program units and non-Acid Rain subpart H units. The 
revisions would make a distinction between sources that report emission 
data on a year-round basis and those that report data only during the 
ozone season. These changes were proposed to help owners and operators 
of non-Acid Rain Program units to more easily determine whether a unit 
can qualify for LME status. EPA proposed to clarify what the LME 
thresholds are for Acid Rain Program units and subpart H units.
    EPA also proposed to make a minor revision to the definition of a 
LME unit in Sec. 75.19(a)(1) by removing from the definition 
the terms "gas-fired" and "oil-fired" and 
adding a parenthetical, "(i.e., diesel fuel or residual 
oil)" after the words, "fuel oil". The Agency did not 
propose to expand the use of LME methodology beyond units that burn 
fuel oil and natural gas.
c. What Changes Is EPA Finalizing?
    EPA received substantive comments on the proposed clarification of 
the applicability of the LME methodology, requesting that the criteria 
to qualify for LME status be made less restrictive. In response to 
these comments, today's rule increases the NO_X low mass 
emissions threshold for year-round reporters from 50 to less than 100 
tons per year and increases the NO_X low mass emissions 
threshold for ozone season-only reporters from 25 to 50 tons per ozone 
season. For units that choose to (or are required to) report emissions 
data on a year-round basis, no more than 50 tons of the annual 
NO_X limit may be emitted during the ozone season. Today's 
rule also revises the definition of a "low mass emissions 
unit" in Sec. 72.2 , expanding the applicability of the 
LME provisions to include units that burn gaseous fuels other than 
natural gas.
Discussion
    Two commenters requested that EPA raise the NO_X emission 
thresholds for LME qualification (KeySpan Corporation (KeySpan); PSEG 
Fossil LLC (PSEG)). One commenter recommended raising the annual 
NO_X threshold to 100 tons per year, noting that many peaking 
units emit less than 100 tons of NO_X per year and that such 
units are often unmanned, making it difficult to properly maintain and 
operate continuous monitoring systems (KeySpan). Another commenter 
asked EPA to consider raising the LME threshold for ozone season-only 
reporters to 100 tons per ozone season (PSEG). In response to these 
recommended rule changes, EPA performed additional data analysis to see 
if raising the LME thresholds for NO_X could be justified, 
consistent with the principles EPA articulated in the 1998 rule for 
limiting eligibility to use LME. The results of that data analysis 
showed that raising the annual NO_X threshold from 50 to 
under 100 tons per year and increasing the ozone season threshold from 
25 to 50 tons per ozone season are both defensible and consistent with 
the Agency's original intent, and accomplish Clean Air Act objectives. 
In the October 27, 1998 final rule, Finding of Significant Contribution 
and Rulemaking for Certain States in the Ozone Transport Assessment 
Group (OTAG) Region for Purposes of Reducing Regional Transport of 
Ozone (63 FR 57485), EPA laid out the applicability criteria for LMEs 
and initially concluded that NO_X thresholds as high as those 
adopted today would result in inappropriate types of sources being able 
to use LME, and in too many tons of NO_X emissions being 
exempted from CEMS. However, based on the extensive data EPA has 
subsequently collected under the Acid Rain Program and the Ozone 
Transport Commission (OTC) NO_X Budget Program, and in 
response to numerous persuasive source-specific petitions as well as 
comments on the proposed rulemaking, EPA has re-assessed its position 
in 1998, and now concludes that a cutoff of less than 100 tons 
NO_X per year, no more than 50 tons of which may be emitted 
in any ozone season, is both defensible and reasonable, as discussed 
below.
    There are a number of reasons that the Agency is electing to reopen 
this issue at this time. First, a considerable number of units that 
currently are not subject to the Acid Rain Program (ARP), and thus part 
75 monitoring, will be required to continuously monitor their emissions 
under part 75 as a result of the implementation of the NO_X 
SIP Call. These units include a number of smaller existing units that 
Congress explicitly exempted from the Acid Rain Program under title IV 
of the Act. Some of these turbines currently monitor under the 
provisions of the OTC NO_X Budget Program, generally by using 
default monitoring approaches, while others are located in other 
NO_X SIP Call States. In addition, these units include units 
less than 25 MWe that some OTC States have included in their 
NO_X SIP Call programs, as well as non-EGUs that are covered 
by the NO_X SIP Call. In some States, these units become 
subject to part 75 monitoring as early as the 2002 ozone season as part 
of the States' implementation of their NO_X SIP Call-related 
programs. These non-Acid Rain Program units face the expenditure of 
considerable resources to measure a rather limited portion of the total 
NO_X emissions.
    Also, many new units being built to fulfill increased electricity 
demand are unmanned, gas-fired turbines with low NO_X burner 
technology. These units, in many cases, will be required to account for 
emissions under State implementation plans to reduce NO_X in 
the NO_X SIP Call regions of the eastern United States. 
Unlike units with add-on technologies (such as selective catalytic 
reduction (SCR)) where continual oversight is required to maintain low 
emissions performance, these units reliably operate at a low and 
consistent emissions level. Consequently, the degree of confidence the 
Agency can have in the attainment of overall program goals has 
increased, while the risks associated with underestimation of emissions 
from these units appears less significant. For unmanned sites, the use 
of CEMS provides additional challenges for owners and operators and 
these concerns are an additional reason for the Agency to evaluate the 
LME provisions.
    In evaluating the LME provisions, the Agency has established a de 
minimis test as an internal program check to assure that only a de 
minimis level of emissions from all regulated sources are allowed to 
use exemptions from the Acid Rain Program or monitoring methods under 
Part 75 (including the new unit exemption, appendix E and LME 
provisions). In the October 27, 1998 Federal Register, when the Agency 
last considered this issue (63 FR 57486), the de minimis evaluation was 
based on, among other things, projections of the cumulative effect of 
the new National Ambient Air Quality Standards (NAAQS) for ozone (O3), 
NO_X SIP Call, Phase II of the ARP, and other State and 
regional programs (such as the OTC). The 1998 preamble established a 
one percent de minimis threshold of about 20,000 tons per year, 
covering all CEMS-exempted methods, on the basis of preliminary 
information which indicated that future NO_X emissions after 
implementation of these various CAA programs would be approximately two 
million tons per year. This de minimis threshold constituted a revision 
of the approximately 40,000 ton level EPA had originally discussed in

[[Page 40402]]

the 1993 rule for CEMS-exempted methods.
    Since that time, the Agency has developed updated information on 
projected year 2010 emissions from the utility sector. First, in 1999, 
pursuant to the CAA Amendments EPA published its section 812 
prospective study of benefits under the CAA (Final Report to Congress 
on Benefits and Costs of the Clean Air Act, 1990 to 2010, EPA 
410-R-99-001). This document estimates that total 
utility emissions would be approximately 3.7 million tons per year in 
2010. The analysis assumes implementation of the NO_X SIP 
Call in the entire OTAG modeling domain. In fact, the SIP Call covers 
only a portion of the OTAG region (excluding States in EPA Region 1 
(ME, NH, and VT), Region 4 (FL and MS), Region 5 (MN and WI), Region 6 
(AR, LA, OK, and TX), Region 7 (IA, KS, NE), and Region 8 (ND and SD). 
Since that report, EPA has updated its estimates for 2010 post-CAA 
implementation NO_X emissions, and, as of October 2001, 
estimates approximately 4.3 million tons of NO_X per year 
after implementing major CAA programs such as Phase II of the Acid Rain 
Program and the NO_X SIP Call (see Docket No. 
A-2000-33, Item IV-A-7). As a result of this 
updated information, EPA believes that the de minimis analysis should 
reflect current projections and start with a one percent target level 
of 43,000 total tons for CEMS-exempted methods.
    As indicated in the 1998 rulemaking, the Agency's determination of 
the appropriate level of NO_X emissions to be considered de 
minimis needs to be based on "all units that may be covered by 
the de minimis exceptions from the requirement to use CEMS, i.e. all 
units using the new unit exemption, appendix E, and the new low mass 
emissions methodology" (63 FR 57486). Because considerably more 
information on these regulated sources is now available, the Agency 
undertook a reevaluation of the potential number of various units that 
may choose excepted methodologies to account for their emissions rather 
than installing CEMS (see Docket No. A-2000-33, Item 
IV-A-6).
    EPA's recent analysis (Docket No. A-2000-33, Item 
IV-A-6) shows that as of December 2001, there were 763 
exempt new units. This total is significantly higher than the 1998 
projection of 278 units. These units, based on EPA's tons per unit 
estimate developed in 1993 for the new unit exemption (see 58 FR 3590, 
January 11, 1993), have estimated emissions of approximately 8,700 
tons. Exempt units are those new units under the Acid Rain Program that 
are less than or equal to 25 MWe and burn clean fuel with low sulfur 
content.
    The next class of units subject to the de minimis threshold are 
units that monitor based on appendix E of part 75. These appendix E 
units are gas-or oil-fired peaking units. At the end of the year 2000, 
there were 263 appendix E units, and those units emitted slightly more 
than 14,000 tons of NO_X per year. In the 1998 preamble, EPA 
used 1997 data to show that there were approximately 235 units that 
used appendix E and that these units had approximately 11,000 tons of 
NO_X per year.
    Finally, we examined the number of units that could potentially 
qualify for LME status under the new NO_X thresholds. We 
conducted the analysis for both ARP units and non-ARP units that will 
become subject to part 75 under the NO_X SIP Call. For this 
analysis, we used emissions data from the ARP and OTC programs and data 
from the NO_X SIP Call baseline inventories to evaluate 
multiple years of emissions data for each unit. We assumed that units' 
actual rates would be comparable to their fuel- and unit-specific 
tested emissions rates as allowed for under the LME provisions except 
for units with rates less than 0.15 lb/mmBtu, where we used 0.15 lb/
mmBtu as a default given the requirements in Sec. 75.19. The 
other assumptions and details of the analysis are included in Docket 
Item IV-A-6.
    For Acid Rain Program units only, the change from a 50 to 100 tons 
of NO_X per year threshold would increase the number of 
existing units that could qualify by about 50 units with a total of 
3,000 tons. This excludes appendix E units that already qualify for de 
minimis monitoring. This increase in potential LME units, taken 
together with emissions from appendix E units and exempt new units, 
would result in approximately 27,000 tons of NO_X per year 
subject to the de minimis target level.
    For the NO_X SIP call, the increase from a threshold of 
25 tons of NOX per ozone season to 50 tons per ozone season could 
increase the total number of existing non-ARP units that may qualify 
for LME by slightly more than 200 units. About 70 of those units are 
units in the OTC region that are under 25 MWe and currently monitor 
using default values under the OTC NO_X Budget Program. These 
units generally would also qualify for appendix E monitoring if the 
NO_X threshold was not increased. The total increase in tons 
that may be monitored using appendix E or LME provisions under an 
increased ozone season NO_X threshold would be approximately 
2,000 tons per ozone season (an increase from about 5,500 to 7,500 tons 
per ozone season from these non-ARP units). Together with the estimated 
total of 27,000 tons per year NO_X from the ARP units, the 
total amount of emissions from units within the group under the de 
minimis concept conservatively represents approximately 35,000 tons of 
emissions. This total remains below the 43,000 tons target level based 
on one percent of projected year 2010 emissions and allows for future 
growth of new units that qualify for LME, appendix E, or the new unit 
exemption. It is also important to remember that the LME analysis 
accounts for units that could potentially qualify for LME monitoring 
requirements; not all units that potentially qualify will necessarily 
use the LME provisions. For example, the 1998 preamble (63 FR 57487) 
estimated that 224 units would qualify at the LME thresholds 
promulgated at that time. In the year 2000, two units used the LME 
provisions. Since that time, the number has increased quickly, 
primarily because of new turbine units that likely also would qualify 
for the appendix E methodology.
    It is important to note that units electing alternative 
methodologies such as LME status and appendix E are still accountable 
for all their emissions using default emissions values or conservative 
test results. What they are relieved from is installing CEMS. The 
Agency was able to evaluate the long term (quarterly) emission rates 
for a number of units that had switched from the use of appendix E to 
the use of CEMS over the past few years. That study (see Docket No. 
A-2000-33, Item IV-A-8) examined 41 ARP units, 
and paired quarters from similar seasons with a minimum number of 
operating hours. While the lack of data from simultaneous time periods 
limits the ability to draw precise conclusions from this analysis, the 
analysis did show that the quarterly emission rates were, on average, 
slightly higher when units measured with appendix E rather than CEMS 
(approximately 4 percent). Because the appendix E and LME provisions 
rely on the same basic test procedures to establish a fuel- and unit-
specific default rate, this analysis is relevant to the LME provisions 
as well. The Agency believes this analysis also supports the change in 
the LME thresholds that EPA is finalizing in this rulemaking by 
indicating that significant under-reporting of emissions should not 
occur as a result of using the LME provisions. We also think it 
provides further support for the reliability of estimates in

[[Page 40403]]

our de minimis analysis that is based primarily on existing CEMS data 
for estimating the tonnage from potential LME units.
    At the same time, the analysis did indicate that in particular 
situations, appendix E values could be below reported CEMS values. In 
light of this finding that appendix E (and by extension LME) monitoring 
will not always produce conservative values, use of alternative methods 
of monitoring should remain constrained by the de minimis threshold EPA 
has established. This finding also suggests that these monitoring 
methods may not be appropriate alternatives to CEMS in other programs 
(such as trading programs with much lower caps, or programs with short 
term emission limits such as Best Available Control Technology (BACT) 
or Lowest Achievable Emission Rate (LAER) requirements established 
through New Source Review permits).
    Cumulatively, the data indicate that if the LME threshold were 
raised to 50 tons per ozone season, it would allow 95 percent of the 
numerous small units in the OTC NO_X Budget Program that 
currently use non-CEMS methodologies (which are, in many cases, similar 
to LME) to qualify as LME units under the NO_X Budget Trading 
Program. If the threshold were not raised, only about 65 percent of 
these same small units could qualify as LME units. EPA considers a less 
burdensome transition for these smaller units from the OTC Program to 
the larger NO_X Budget Trading Program to be highly 
desirable. Allowing these units to use LME methodologies under part 75 
(which are similar to methodologies currently used under the OTC 
Program), rather than CEMS requirements under part 75, will reduce 
economic and administrative burden for both the affected sources and 
the regulatory agencies. Further, LME methodologies are reasonably 
accurate methods given the small amount of emissions contributed by 
this class of units. In view of these considerations, EPA has concluded 
that there are distinct benefits, and no significant environmental 
risks, in raising the LME qualifying NO_X thresholds to 50 
tons per ozone season and less than 100 tons per year, respectively. 
Therefore, these higher emission threshold values are promulgated in 
today's rule. However, note that for units subject to the 
NO_X Budget Trading Program, the final rule places a 
constraint on the 100 tons per year NO_X limit: no more than 
50 of the 100 tons per year may be emitted during the ozone season. EPA 
has added this constraint for purposes of consistency, so that all 
NO_X Budget units using the LME methodology will be limited 
to 50 tons of NO_X emissions per ozone season, whether data 
are reported on a year-round basis or only during the ozone season. In 
addition, should cost of monitors go down, or if the ceiling turns out 
to be much lower than that which we have projected herein, the Agency 
reserves the right to re-assess any and all of these exceptions in the 
future if the need arises.
    Regarding the definition of a LME unit as presented in 
Sec. 72.2 and in Sec. 75.19(a), one commenter 
questioned why the definition appears to restrict LME qualification to 
units that burn only fuel oil and natural gas (UARG). The commenter 
suggested that the broader terms "gas-fired" and 
"oil-fired" be used as the criteria for determining LME 
applicability so that units burning "other" gaseous fuels, 
such as landfill gas, would also be allowed to use the LME methodology. 
After careful consideration of these comments, EPA agrees that there is 
no compelling reason for excluding other types of gaseous fuels from 
LME applicability. Further, the Agency believes that this change will 
reduce the administrative burden on both the sources and the regulatory 
agencies, by providing a way for low-emitting sources that burn 
"other" gaseous fuels to meet part 75 requirements without 
having to submit special petitions under Sec. 75.66. Therefore, 
today's rule expands the applicability of the LME methodology to 
include units that burn gaseous fuels other than natural gas.
    In order for a unit that burns one of these "other" 
gaseous fuels to qualify as a LME unit, fuel- and unit-specific default 
emission rates would have to be established. If the unit is Acid Rain-
affected, Sec. 75.19(a)(1)(i)(C) of today's rule requires the 
sulfur content of the fuel to be characterized by performing the 720-
hour demonstration described in revised section 2.3.6 of appendix D, 
before the unit can qualify for LME status. The results of that 
demonstration may be used to determine a default SO₂ 
emission rate for the fuel, unless the fuel is found to have both a 
high sulfur content and a high sulfur variability (i.e., variability 
with a standard deviation of greater than 5.0 grains per 100 scf); 
should that occur, the unit would be ineligible for LME status. To 
derive a default CO₂ emission factor for the fuel, revised 
Sec. 75.19(c)(1)(iii) requires Equation G-4 in appendix G 
to be used, in conjunction with a carbon-based F-factor calculated from 
the results of fuel sampling and analysis. To determine the default 
NO_X emission rate for the gaseous fuel, revised 
Sec. 75.19(c)(1)(ii) requires fuel- and unit-specific emission 
testing to be performed.
2. How Does Today's Rule Change the Certification Application 
Procedures and Requirements for Low Mass Emissions Units?
Background
a. What Is Currently Required?
    In response to concerns raised by both regulated entities and other 
regulatory agencies, EPA examined the administrative procedures in part 
75 pertaining to LME units, especially the certification application 
procedures. It was determined that these procedures could be clarified 
to simplify program implementation and to make the LME requirements as 
consistent as possible with other sections of part 75.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed requiring the electronic portion of 
the LME certification application be sent to the Administrator and the 
hardcopy portion to the appropriate Region and State. The Agency also 
proposed requiring that LME certification applications be submitted no 
less than 45 days prior to the date on which use of the methodology is 
projected to commence; and the projected commencement date be indicated 
in the application.
    In addition, EPA proposed clarifications to the requirements for 
new or newly affected units and the extent to which a LME applicability 
demonstration could rely on projected emissions instead of actual, 
historical data. Finally, EPA proposed clearer definitions for the date 
of provisional certification for LME units.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the provisions requiring submission of the 
LME certification application at least 45 days before the methodology 
is projected to be used and specification of the projected commencement 
date in the application. The final rule also clarifies that the 
methodology is considered to be provisionally certified as of the date 
of submittal of the certification application, but may not be used to 
report data prior to the projected commencement date.
    In response to substantive comments regarding the initial LME 
certification application procedures, in particular the manner in which 
actual historical emissions data, projected emissions, and calculated 
emissions are used to demonstrate that a unit qualifies for LME status, 
today's rule adds significant flexibility to the way in which a unit

[[Page 40404]]

can initially qualify. The final rule allows existing units to claim 
LME status using projected emissions rather than historical data, if a 
Federally enforceable permit restriction is taken which limits unit 
operation, or if the owner or operator has recently installed emission 
controls on the unit.
    Today's rule also simplifies the application procedure by removing 
from Sec. 75.19(a)(2) the requirement that the certification 
application must include calculated emissions for the previous three 
years in addition to the actual historical data for those years. For 
purposes of the initial certification application, the final rule 
allows the owner or operator of a new unit to use conservatively high 
default NO_X emission rates other than the values listed in 
Table LM-2 to project the unit's emissions.
Discussion
    EPA received no comments on the proposed changes and clarifications 
to the LME administrative processes. Therefore, these provisions have 
been finalized, with only minor editorial changes for added clarity and 
consistency. However, two commenters objected to the manner in which an 
existing unit qualifies for LME status, believing it to be overly 
restrictive (West Virginia Manufacturers Association, PSEG). The rule 
requires three years or ozone seasons of historical data to demonstrate 
that the unit is a LME. The commenters objected to this provision 
because it automatically excludes units if their recent historical 
NO_X emissions have been above the LME thresholds, even if 
the source owner or operator is willing to take an enforceable permit 
restriction on the number of operating hours in future years. Both 
commenters recommended that Sec. 75.19 be revised to 
conditionally allow existing units to qualify for LME status 
prospectively, rather than retrospectively. A third commenter objected 
to the apparent requirement in Sec. 75.19(a)(2)(i) for new 
units to use the generic NO_X default emission rates from 
Table LM-2 to project the unit's NO_X emissions in the 
initial certification application (Machaver). The commenter recommended 
that EPA allow the use of a conservative but more realistic estimate of 
the unit's emissions (e.g., the permitted NO_X emission limit 
or 0.15 lb/mmBtu for units with add-on controls) for the purpose of the 
initial certification application.
    After consideration of these comments, EPA has revised the 
requirements for a unit to initially qualify as a LME unit. The 
revisions to Sec. 75.19(a) affect both new and existing units. 
The final rule allows the owner or operator to claim LME status for a 
unit in the following ways:
    1. Using three years (or ozone seasons) of actual data from 
electronic data reporting (EDR) submittals under part 75 or under the 
OTC NO_X Budget Program or, if such reports are unavailable, 
using estimates of the actual emissions from other sources of 
information (including default emission rates, emission rates derived 
from stack testing or part 60 CEMS, fuel sampling results, fuel usage 
records); or
    2. Based on three years (or ozone seasons) of projected emissions 
for new units with no actual, historical data; or
    3. Using a combination of actual and projected emissions totaling 
three years (or ozone seasons), if :
    (a) Three years (or ozone seasons) of actual emissions data cannot 
be provided (e.g., for a unit that has been in operation for only one 
or two years); or
    (b) An existing unit takes a Federally enforceable permit 
restriction on unit operating hours in order to stay below the LME 
emission thresholds; or
    (c) The emissions during any of the three previous years (or ozone 
seasons) are not representative of present or future emissions because 
the owner or operator has recently installed emission controls on the 
unit.
     Section 75.19(a)(4) of today's rule also allows the owner or 
operator of a new unit to use default NO_X emission rates 
other than the ones in Table LM-2 to project the unit's emissions 
in the initial certification application. The final rule allows the use 
of estimated NO_X emission rates which are lower than the 
Table LM-2 values, provided that the estimates are still 
conservatively high with respect to the expected actual emission rates. 
For instance, for a new gas-fired turbine that uses selective catalytic 
reduction (SCR) to control NO_X emissions, an estimated 
emission rate of 0.15 lb/mmBtu could be used in lieu of the Table 
LM-2 generic default of 0.7 lb/mmBtu. For units that use water/
steam injection or dry low-NO_X (DLN) technology, an emission 
rate based on the permit limit could be used. For units without 
NO_X emission controls, the emission rate estimate could be 
based on historical emission test data. However, 
Sec. 75.19(a)(4) makes it clear that these estimated 
NO_X emission rates are to be used only for the purposes of 
the initial certification application. The estimated emission rates may 
not be used for reporting purposes in the time period extending from 
the first hour in which the LME methodology is used to the date and 
hour in which the actual emission rate is established by fuel- and 
unit-specific emission testing. During that interval, either the Table 
LM-2 value or the maximum potential emission rate must be 
reported. EPA believes that these new provisions in 
Sec. 75.19(a)(4) will ensure that new units are not unfairly 
excluded from using the LME methodology and will also provide a strong 
incentive to the owners or operators to perform the NO_X 
emission rate testing in a timely manner.
    EPA notes that when the initial estimate of NO_X emission 
rate for the LME certification application is derived from historical 
emission test data, it may be prudent to base the estimate on data 
collected under process operating conditions (e.g., heat input rate, 
unit load.) comparable to those at which the highest NO_X 
emission rates are expected to occur during the four-load appendix E 
test. This will help to ensure that the unit's LME status is not 
jeopardized since the estimated NO_X emission rate will 
likely be close to the actual default emission rate that is derived 
from the appendix E testing and used for emissions reporting.
3. How Will Today's Rule Affect the Way in Which Fuel- and Unit-
Specific NO_X Emission Rates Are Determined for Low Mass 
Emissions Units?
Background
a. What Is Currently Required?
    The low mass emissions methodology in Sec. 75.19 provides 
two options for determining the appropriate default NO_X 
emission rate for a unit. The owner or operator may either use a 
generic default emission rate from Table LM-2, or determine a 
fuel- and unit-specific default NO_X emission rate by 
performing emission testing, using appendix E test methodology. If the 
testing option is selected, Sec. 75.19(c) specifies how to 
determine the default emission rate. For uncontrolled units, the 
default emission rate is the highest rate obtained from the emission 
testing, multiplied by 1.15. The reason for the 1.15 multiplier is to 
prevent underestimation of emissions, since the NO_X emission 
rate can vary at a given load. For units with NO_X emission 
controls of any kind, the default emission rate is the higher of: (a) 
the highest rate from the emission testing multiplied by 1.15; or (b) 
0.15 lb/mmBtu. The reason for specifying a "floor" emission 
rate value of 0.15 lb/mmBtu for units with NO_X emission 
controls is principally to ensure that large units with a high 
potential to emit and with controls such as SCR and selective non-
catalytic reduction (SNCR) would not use the LME provisions to estimate 
emissions. Units with these

[[Page 40405]]

controls can achieve emissions rates much lower than 0.15 lb/mmBtu and 
therefore would not want to use the 0.15 lb/mmBtu floor under the LME 
provisions to report their emissions. EPA believes that for units with 
such controls, continuous NO_X emission monitoring is the 
preferred way to determine that a unit achieves its target control 
level. This is because the NO_X emission reductions achieved 
with these controls can vary significantly with the manner in which the 
controls are operated and the manner of proper operation is difficult 
to document and demonstrate.
    After promulgating the LME provisions on October 27, 1998, EPA 
continued to investigate the causes of variability in NO_X 
emission rates in combustion turbines by reviewing literature, 
reviewing test results, analyzing CEMS data for turbines, and 
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_X emission rate in 
combustion turbines. The investigation revealed that several 
empirically-derived mathematical algorithms have been developed to 
correct a measured NO_X concentration to a theoretical 
NO_X concentration at a different temperature, pressure, and 
humidity, including the equation in subpart GG, Standards of 
Performance for Stationary Gas Turbines (40 CFR 60.335).
    EPA also investigated the claims of industry representatives who 
asked the Agency to consider allowing the use of controlled fuel- and 
unit-specific NO_X emission rates below the 0.15 lb/mmBtu 
minimum for turbines with water injection, steam injection, or water/
fuel emulsion. The representatives had 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 was within acceptable 
limits would not underestimate emissions. To substantiate these claims, 
EPA reviewed data from CEMS installed at turbines with water-and-steam 
injection and water/fuel emulsion. As a result of this review, EPA 
concluded that if the water-to-fuel ratio is monitored, effective and 
constant control of NO_X will be achieved, with little chance 
of underestimation of NO_X emissions (see Docket 
A-2000-33, Item II-B-1).
b. What Changes Were Proposed?
    As a result of these two investigations, EPA proposed the following 
revisions to Sec. 75.19(c) on June 13, 2001. First, EPA 
proposed adding a new requirement for certain turbines to correct 
measured NO_X concentrations to ambient conditions of 
temperature, pressure, and relative humidity at the time of the 
emission test. This proposed correction (Equation LM-1a in 
Sec. 75.19(c)(1)(iv)(A)(4)) would apply only to uncontrolled 
diffusion flame style turbines. It would compensate for temperature and 
humidity effects on NO_X formation by correcting the measured 
NO_X concentrations at the test conditions to the average 
annual temperature, atmospheric pressure, and humidity at the location 
of the turbine. It also would prevent underestimation or overestimation 
of NO_X emissions for uncontrolled diffusion flame turbines 
and would remove the requirement to multiply the measured 
NO_X emission rates for such turbines by 1.15.
    Second, EPA proposed revising Sec. 75.19(c)(1)(iv)(H)(1) to 
allow the use of measured fuel- and unit-specific NO_X 
emission rates for units with water or steam injection (and no other 
type(s) of add-on NO_X controls), even if the measured 
emission rates are below 0.15 lb/mmBtu. This proposed change would 
remove the current rule requirement that all tested emission rates 
below 0.15 lb/mmBtu must be adjusted upward to a default value of 0.15 
lb/mmBtu. The proposed change would require 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.
c. What Changes is EPA Finalizing?
    EPA received numerous substantive comments on the proposed changes 
to Sec. 75.19(c). Based on these comments, the Agency finalizes 
the proposed revisions to Sec. 75.19(c)(1)(iv)(A)(4) with only 
minor editorial changes, but modifies the proposed changes to 
Sec. 75.19(c)(1)(iv)(H)(1). Today's rule requires fuel- and 
unit-specific NO_X emission rates for uncontrolled diffusion 
flame turbines to be corrected to ISO standard conditions, and removes 
the requirement to multiply the tested emission rates by 1.15. The 
final rule also allows units that use steam (or water) injection and 
have no other add-on controls, or DLN technology and have no other add-
on controls, to use the highest tested emission rate for reporting 
purposes during controlled hours instead of reporting 0.15 lb/mmBtu. 
Units equipped with SCR or SNCR controls still must report the 
"floor" NO_X emission rate of 0.15 lb/mmBtu if it 
is higher than the tested emission rates, with one exception: if the 
unit uses steam (or water) injection or DLN technology in addition to 
the SCR or SNCR controls, then the highest tested emission rate may be 
reported for controlled hours in lieu of reporting 0.15 lb/mmBtu, 
provided that the emission testing is performed either upstream of the 
SCR (or SNCR) or at a time when the SCR (or SNCR) is not in operation.
Discussion
    Two commenters objected to the provision requiring units that use 
NO_X emission controls other than water or steam injection to 
adjust their tested emission rates upward to 0.15 lb/mmBtu (Clean Air 
Energy; Exelon Corporation (Exelon)). In particular, the commenters 
noted that for combustion turbines using DLN control technology, the 
0.15 lb/mmBtu "floor" emission rate is several orders of 
magnitude higher than the guaranteed emission levels from such units. 
One of the commenters recommended that EPA treat turbines with DLN 
control in the same manner as turbines that use water or steam 
injection (Exelon). That is, EPA should allow the highest tested 
emission rate to be reported during hours in which parametric data are 
available to document proper operation of the DLN controls. The 
commenter provided supplementary information, suggesting parameters 
that could be monitored to ensure that the DLN is operating in the low-
NO_X, or premixed, mode.
    Based on the supplementary information provided by the commenter 
and discussions with turbine experts (see Docket A-2000-33, 
Item IV-A-1), EPA has decided to incorporate the 
commenter's suggestion to treat LME units with DLN technology in the 
same manner as LME units with water-and-steam injection. Today's rule 
allows the highest emission rate from the appendix E tests to be 
reported as the default NO_X emission rate for the unit, if 
proper operation of the emission controls is documented. Section 
75.19(c)(1)(iv)(H) of the final rule specifies that for DLN technology, 
"proper operation" of the emission controls means that the 
unit is in the low-NO_X or premixed combustion mode and fired 
with natural gas. Evidence of operation in the low-NO_X or 
premixed mode is provided by monitoring the appropriate turbine 
operating parameters. These parameters may include percentage of full 
load, turbine exhaust temperature, combustion reference temperature, 
compressor discharge pressure, fuel and air valve positions, dynamic 
pressure pulsations, internal guide vane (IGV) position, and flame 
detection or flame scanner condition. The acceptable values and ranges 
for all parameters

[[Page 40406]]

monitored must be specified in the monitoring plan for the unit, and 
the parameters must be monitored during each unit operating hour. If 
one or more of these parameters is not within the acceptable range or 
at an acceptable value in a given operating hour, or if the unit is 
fired with oil, the fuel- and unit-specific NO_X emission 
rate may not be used for that hour and the appropriate default 
NO_X emission rate from Table LM-2 must be reported, 
instead.
    Two commenters recommended that EPA revise 
Sec. 75.19(c)(1)(iv)(C)(4) and (c)(1)(iv)(C)(6) to allow 
units with NO_X emission controls of any kind to use the 
Federally-enforceable permit limit to determine the default 
NO_X emission rate for an LME unit, and then to use the 
required periodic testing under title V of the CAA to verify that the 
emission limit is being met (Class of '85 Regulatory Response 
Group (Class of '85); Reliant Energy (Reliant)). EPA did not 
incorporate the commenters' suggested approach, although the 
Agency notes that today's rule provides some relief to controlled units 
from the requirement to use 0.15 lb/mmBtu as the default emission rate 
when the tested NO_X emission rates are less than 0.15 lb/
mmBtu. In the final rule, that requirement applies only to units that 
use SCR or SNCR for NO_X emission control. In all other 
cases, LME units with NO_X emission controls may use their 
highest tested emission rate as the default value during controlled 
hours.
    For add-on controls such as SCR or SNCR, proper operation of the 
controls depends on whether the desired chemical reaction necessary to 
reduce NO_X emissions is actually occurring which, in turn, 
depends on many factors (e.g., whether the catalyst is active, whether 
the reagent injection rates are appropriate). Other than direct 
measurement of emissions using a CEMS or reference method, there is no 
known way to ensure that the catalyst or injected reagents are 
producing the expected emission reductions. Periodic title V emission 
testing, as recommended by the commenter, would not provide adequate 
assurance that the SCR or SNCR controls are operating properly on a 
continuous basis; because the test is "periodic," at best 
it shows these controls are working when the test is being performed. 
Therefore, the final rule retains the requirement to use the 0.15 lb/
mmBtu "floor" NO_X emission rate for units 
equipped with SCR or SNCR. EPA notes, however, that if a unit uses SCR 
(or SNCR) and steam/water injection, the final rule allows the highest 
tested emission rate (provided it is less than 0.15 lb/mmBtu) to be 
used in lieu of 0.15 lb/mmBtu, if the steam/water injection is 
operational during the emission testing and if the testing is either 
performed upstream of the SCR (or SNCR) or with the SCR (or SNCR) not 
operating. Similarly, for a unit that controls NO_X emissions 
using DLN technology and SCR (or SNCR), the highest tested emission 
rate may be used provided that it is less than 0.15 lb/mmBtu, and the 
testing is performed when DLN technology is in use and the SCR (or 
SNCR) is not operating (see Sec. 75.19(c)(1)(iv)(C)(7) 
and 75.19(c)(1)(iv)(C)(8)).
4. Does Today's Rule Allow Testing To Be Done at Fewer Than Four Load 
Levels To Determine Fuel- and Unit-Specific NO_X Emission 
Rates for Low Mass Emissions Units?
Background
a. What Is Currently Required?
    The current LME provisions in Sec. 75.19(c)(1)(iv)(A) 
require testing at four load levels, using the test methodology in 
appendix E of part 75, for all units which opt to determine a default 
fuel- and unit-specific NO_X emission rate. Industry 
representatives have asked that this requirement be waived for units 
which operate at a single load only.
b. What Changes Were Proposed?
    In the June 13, 2001 proposed rule, EPA proposed and solicited 
comments on two options as alternatives to the four load testing 
requirement for LME units. Option 1 would require the first appendix E 
test to be performed at four loads, with future single load re-tests at 
the load level at which the highest emission rate was found. Option 2 
would allow single-load testing for units that provide a demonstration 
that the unit operates at a single load level.
    In the preamble to the proposed rule, EPA expressed a preference 
for Option 2. Therefore, the Agency proposed adding a new section, (I), 
to Sec. 75.19(c)(1)(iv) which is consistent with Option 2. The 
proposed revisions would conditionally allow single-load testing to be 
performed if the owner or operator demonstrates that the unit has 
operated at a single load level for at least 85 percent of the time in 
the three years prior to the emission test. Turbines that operate at a 
set-point temperature and not at a particular load level would also be 
conditionally allowed to perform single level testing, if it can be 
demonstrated that the unit has operated within ± 10 percent of 
the set-point temperature for at least 85 percent of the time in the 
three years prior to the emission test. EPA also proposed in 
Sec. 75.19(c)(1)(iv)(I) that for a set-point turbine which 
normally operates at base load but is capable of operating at a higher 
(peak) load level, if the emission testing is only performed at base 
load, then the fuel- and unit-specific NO_X emission rate 
obtained from the testing would have to be adjusted upward during peak 
load operation by using a multiplier of 1.15 to ensure that emissions 
are not underestimated.
c. What Changes Is EPA Finalizing?
    EPA received numerous substantive comments on the proposed options 
for reducing the number of required load levels at which testing is 
required to determine fuel- and unit-specific NO_X emission 
rates for LME units. After carefully considering these comments, the 
Agency has decided to incorporate both of the proposed Options 1 and 2 
into the final rule. These provisions are found in 
Sec. 75.19(c)(1)(iv)(I) and (J) of today's rule. EPA 
notes that Option 2 has been modified somewhat from the proposal. The 
final rule allows testing of LME units to be performed at either one, 
two, or three loads instead of four, based on the results of a 
historical load analysis for the previous three years (or three ozone 
seasons for sources that report emissions data only for the ozone 
season). The testing is required at however many load levels 
cumulatively represent at least 85 percent of the unit operating hours 
in the previous three years (or ozone seasons).
Discussion
    One commenter supported proposed Option 2, but requested that EPA 
allow the demonstration of single-load operation to be made using only 
ozone season data for sources that report data on an ozone season-only 
basis (Massachusetts Department of Environmental Protection 
(Massachusetts DEP)). Another commenter favored Option 1 over Option 2, 
because Option 2, although "reasonable," could only be used 
by a subset of LME units (NorthWestern Energy & Communications 
Solutions (NorthWestern)). Two commenters recommended that EPA allow 
testing to be done at two loads if historical load data for the unit 
demonstrate consistent operation at two load levels for at least 85 
percent of the time (Massachusetts DEP, Machaver).
    EPA has decided to include both proposed Options 1 and 2 in today's 
rule. The Agency believes that this provides sufficient flexibility for 
the various types of LME units to allow them to qualify for reduced 
testing requirements. The final rule incorporates the suggestion of the

[[Page 40407]]

commenters to allow the 85 percent criterion to be applied on a 
cumulative operating load basis, i.e., perform the testing at the 
number of load levels that cumulatively account for 85 percent of the 
unit operating hours in the three years prior to the emission test. 
Today's rule also allows the historical load analysis to include only 
ozone season data for sources that report emissions on an ozone season-
only basis. These new rule provisions are found in 
Sec. 75.19(c)(1)(iv)(I) and (J).

C. Quality Assurance/Quality Control

1. What Changes to the Method of Determining the NO_X MPC, 
MEC, Span, and Range Are Finalized in Today's Rule?
Background
a. What Is Currently Required?
    In recent years EPA has received many questions, pertaining 
especially to new combustion turbines, about the way in which the 
maximum potential concentration (MPC) and maximum expected 
concentration (MEC) are determined for NO_X and how the 
instrument span and range values are set for NO_X monitors. 
Some of the questioners have requested additional options for MPC and 
MEC determinations and claim that part 75 does not address dry low-
NO_X (DLN) control technology, which is being used on many 
new turbines. Others have questioned the appropriateness of the default 
NO_X MPC value of 50 ppm in Table 2-2 of appendix A for 
new oil- and gas-fired combustion turbines.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to add new options for determining 
the NO_X MPC and MEC values, principally with combustion 
turbines in view. The proposed rule would allow the owner or operator 
to use a reliable estimate of the unit's uncontrolled emissions 
obtained from the manufacturer as the MPC value. For units that have 
add-on emission controls or that use DLN technology, the Federally-
enforceable permit limit could be used as the MEC.
    EPA also proposed replacing the 50 ppm default NO_X MPC 
value in Table 2-2 for new combustion turbines 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. EPA 
believes, based on a preliminary data analysis of emissions from new 
combustion turbines, that these values are much more representative of 
actual NO_X emissions from turbines during unit startup and 
periods when the emission controls are not operational (see Docket 
A-2000-33, Item II-B-1).
c. What Changes Is EPA Finalizing?
    EPA received no adverse comments on these proposed rule changes. 
Therefore, today's rule finalizes as proposed the new options for 
determining NO_X MPC and MEC, and the 150 ppm and 200 ppm 
default MPC values for new combustion turbines. The final rule also 
incorporates two important changes to the general approach for 
determining MPC, MEC, span, and range based on recommendations made by 
the commenters. First, today's rule allows CEMS data from a monitor 
certified under 40 CFR part 60 or under a State program to be used to 
make the initial MPC or MEC determinations. Second, for units with a 
dual span requirement for SO₂ or NO_X, the final 
rule places an upper limit on the full-scale range setting of the low-
scale analyzer in cases where the owner or operator selects the default 
high range option in lieu of operating and maintaining a high monitor 
range. Today's rule restricts the full-scale range of the low-scale 
analyzer to five times the MEC value (where the MEC is rounded upward 
to the next highest multiple of 10 ppm).
Discussion
    Two commenters supported the proposed new option to allow the use 
of a reliable manufacturer's estimate of a unit's uncontrolled 
emissions as the MPC value (UARG; Dynegy, Inc. (Dynegy)). No comments 
were received on the proposal to use the permit limit as the MEC for a 
unit with emission controls, and no comments were received on the 
proposed default MPC values for new combustion turbines. Therefore, in 
the absence of adverse comments these provisions are finalized for the 
reasons stated in the proposal. While these rule changes could require 
owners and operators of combustion turbines currently using the 50 ppm 
NO_X MPC value from Table 2-2 of appendix A to change 
their MPC and span values, the Agency believes that many have already 
done so in their required annual re-evaluations of span, range, MPC, 
and MEC values for each monitor. In other words, the owners and 
operators of new combustion turbines using the 50 ppm MPC value from 
Table 2-2 have likely found, upon analysis of actual data, that 
the value is unrealistically low and requires upward adjustment. The 
Agency expects that this rule change will primarily affect new units, 
rather than existing units. However, since there may be some existing 
units still using the 50 ppm MPC value, and since span changes may 
require new calibration gases to be purchased and, in some instances, 
may necessitate analyzer replacement, EPA has provided additional time 
in the rule language from the effective date of today's rule for owners 
and operators to implement the new MPC provision (see Section V., Rule 
Implementation, of this preamble).
    EPA received additional comments on the span and range provisions 
of part 75. Two of these, provided by the same commenter (Machaver), 
are incorporated into the final rule. The commenter asked EPA to 
consider expanding the range of methods for establishing an initial MPC 
or MEC value. The commenter stated that especially for newly-affected 
units, the use of "reasonable, relevant, and appropriate" 
data, such as CEMS data from a part 60 monitor or historical emission 
test data, should be allowed. EPA believes that this suggestion has 
merit, particularly in view of the many sources that will soon be 
required to implement the monitoring provisions of part 75 under the 
NO_X SIP Call. Therefore, today's rule allows any available 
quality-assured CEMS data (whether from a part 75 monitor, a part 60 
monitor, or one that meets State requirements) to be used for the 
initial MPC and MEC determinations. In as much as these initial 
determinations are self-correcting (i.e., appendix A 
Sec. 2.1.1.5 and 2.1.2.5 require an annual review) and 
there are sufficient incentives to ensure proper specification (i.e., 
exceeding a full-scale range necessitates substitution of conservative 
emissions factors under appendix A Sec. 2.1.2.5(b)), the Agency 
sees no harm introduced by providing this additional flexibility. The 
new rule provision is found in sections 2.1.1.1(b), 2.1.1.2(c), 
2.1.2.1(e), and 2.1.2.2(c) of appendix A. Application of these data is 
limited to these initial MPC and MER determinations. Continuous 
emission monitoring systems used for part 75 reporting must meet the 
certification and ongoing quality assurance requirements of part 75.
    The commenter also recommended that EPA set an upper limit on the 
low-scale measurement range for dual span units using the 
"default high range" option. For sources that elect to use 
the default high range option, it is advantageous to set the range of 
the low measurement scale as high as possible to capture emission 
"spikes" and to minimize reporting the default high range 
value of twice the MPC. However, if the low range is set 
inappropriately high, this will result in the majority of the data 
being recorded at the bottom

[[Page 40408]]

end of the measurement scale during normal, controlled, unit operation. 
Data accuracy suffers at the low end of a measurement scale due to a 
poor signal-to-noise ratio. To help ensure that this does not happen, 
the commenter recommended capping the low-scale range at five times the 
MEC, where the MEC is rounded to the nearest 10 ppm. EPA concurs with 
this suggested approach. Today's rule adds the provision to sections 
2.1.1.4(g) and 2.1.2.4(f) of appendix A.
2. What Changes to the 7-Day Calibration Error Test Are Finalized?
Background
a. What Is Currently Required?
    The 7-day calibration error test described in sections 6.3.1 and 
6.3.2 of appendix A of part 75 is required only for initial 
certification, recertification, and occasionally as a diagnostic test. 
It is not a routine, required, periodic quality assurance (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 sometimes infrequent or unpredictable 
nature of peaking unit operation, the 7-day test may take weeks or even 
months to complete.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the 7-day calibration error 
test requirement for monitors installed on peaking units, requiring 
data to be recorded with the unit operating for only three of the seven 
test days. The unit would not be required to be operating for the other 
four days of the test.
c. What Changes Is EPA Finalizing?
    EPA received numerous comments on the proposed revisions to the 7-
day calibration error test procedure. After carefully considering the 
comments, the Agency has decided to remove the 7-day calibration error 
test requirement for peaking units and for SO₂ and 
NO_X monitors with span values of 50 ppm or less. If a unit 
should lose its peaking status, it would also lose its 7-day 
calibration error test exemption. The owner or operator would then be 
required to perform diagnostic 7-day calibration error tests of all 
installed monitors by December 31 of the following year. Today's rule 
reflects these changes, in sections 6.3.1 and 6.3.2 of appendix A and 
in Sec. 75.20(c).
Discussion
    EPA received comments from five different commenters on the 
proposed revisions to the 7-day calibration error test. Four of the 
commenters found the scope of the proposed change to be too narrow as 
it only applies to peaking units (UARG, Dynegy, KVB, Machaver). One 
commenter stated the opinion that part 75 data quality would not be 
jeopardized if the 7-day calibration error test were eliminated for 
peaking units, if not for all units (Dominion). Two other commenters 
provided the following suggestions: (1) Eliminate the 7-day calibration 
error test for all units; or (2) allow combustion turbines to perform 
the test off-line for all 7 days; or (3) restrict the test to zero-
level calibrations for combustion turbines (UARG, Dynegy). Finally, two 
commenters noted that many monitoring systems cannot pass the 7-day 
test using the proposed methodology, i.e., using a combination of off-
line and on-line calibrations, because of differences in temperature 
and pressure between off-line and on-line conditions (UARG, Machaver).
    EPA rejected the commenters' suggestion to eliminate the 7-day 
calibration error test for all affected units. The Agency believes that 
the test has value for frequently operated units, and the test can, in 
most instances, be completed in seven consecutive calendar days. The 
purpose of the 7-day test is to ensure that from day-to-day, a 
continuous emission monitor does not drift excessively while it is 
measuring emissions at stack conditions (e.g., stack pressure and 
temperature). The test provides a one-time demonstration that a monitor 
is capable of consistently passing daily calibrations at a 
specification twice as stringent as the allowable calibration error for 
daily monitor operation. Monitors that cannot meet this requirement are 
disqualified for use under part 75. When the test can be completed in 
seven consecutive days, it achieves its purpose.
    EPA considered removing the 7-day calibration error test 
requirement for all combustion turbines, as suggested by the 
commenters. However, the Agency did not incorporate the commenters' 
recommendation since many combustion turbines are operated as base-load 
or cycling units. Because such units operate frequently, the 7-day 
calibration error test is appropriate and must be performed.
    EPA rejected the commenter's suggestion to allow combustion 
turbines to perform the 7-day calibration error test while the unit is 
off-line. Performing the test off-line defeats the purpose of the test, 
which, as previously noted, is to assess the calibration drift of a 
monitor over a 7-day period while it is in thermal equilibrium with its 
stack environment. The Agency also rejected the commenter's 
recommendation to perform only a calibration with zero-level gas on 
each day of the test. EPA does not believe that it is technically 
justifiable to perform only half of the normal daily calibration 
sequence and to omit the other half. However, EPA does agree with the 
commenters who pointed out that performing the 7-day test using a 
combination of off-line and on-line calibrations would not be a viable 
solution for many monitoring systems.
    In view of these considerations, EPA has decided to remove the 7-
day calibration error test requirement for peaking units and also for 
SO₂ and NO_X monitors with span values of 50 ppm 
or less. With regard to peaking units, the Agency's decision is based 
principally on the difficulties associated with performing the 7-day 
calibration error test in a timely manner for such units. Because 
peaking units operate infrequently, it is often difficult to complete a 
7-day calibration error test within a reasonable time since the test 
must be done with the unit in operation. In cases where a 7-day 
calibration error test may take several weeks or months to complete, 
the test loses its meaning. Today's rule specifies that a peaking unit 
remains exempt from the 7-day calibration error test requirement as 
long as it continues to re-qualify as a peaking unit from year-to-year 
or from ozone season-to-ozone season. However, if at the end of a 
particular year or ozone season peaking unit status is lost, the owner 
or operator must then perform diagnostic 7-day calibration error tests 
of all continuous emission monitors installed on the unit by December 
31 of the following year.
    EPA's decision to exempt SO₂ and NO_X monitors 
with span values of 50 ppm or less from the 7-day calibration error 
test is consistent with changes made in today's rule to section 
2.1.4(a) of appendix B. As discussed below, the final rule lowers the 
allowable calibration error for daily monitor operation to 5 ppm for 
SO₂ and NO_X monitors with span values less than 
or equal to 50 ppm. Since the alternate performance specification in 
section 3.1 of appendix A for the 7-day calibration error test of 
SO₂ and NO_X monitors is also 5 ppm, the changes 
to appendix B will, in effect, require SO₂ and 
NO_X monitors with span values less than or equal to 50 ppm 
to meet the 7-day calibration error test specification every day. This 
makes it unnecessary to

[[Page 40409]]

perform 7-day calibration error testing on these monitors.
3. What Changes to the QA/QC Requirements for Low-Emitting Sources Are 
Finalized?
Background
a. What Is Currently Required?
    Part 75 requires owners and operators of units with SO₂ 
and NO_X monitors to perform daily calibration error tests of 
these monitors. The allowable calibration error is currently 5 percent 
of the span value. However, section 2.1.4(a) in appendix B of part 75 
provides an alternate daily calibration specification for low emitters 
of SO₂ and NO_X. The alternate low-emitter 
specification (for span values less than 200 ppm) is 10 ppm, 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 needs to be tightened. This is especially 
important because many new gas turbines are being built and these units 
have very low NO_X emissions, often in the 0-10 ppm 
range.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to modify the alternate calibration 
error specification in section 2.1.4(a) of appendix B for daily 
operation of SO₂ and NO_X monitors. The 10 ppm 
alternate specification would be retained for span values between 50 
and 200 ppm. However, 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. Also, 5 ppm is the alternate calibration error performance 
specification in section 3.1(b) of appendix A for initial certification 
of SO₂ and NO_X monitors.
c. What Changes Is EPA Finalizing?
    EPA received only one comment on the proposed modification of the 
alternate calibration error specification. The comment was supportive 
(Clean Energy Group). Therefore, today's rule finalizes the proposed 
change to section 2.1.4(a) of appendix B lowering the daily calibration 
error specification to 5 ppm for SO₂ and NO_X 
monitors with span values of 50 ppm or less.
4. What Changes to the Stack Flow-to-Load Ratio Test Are Finalized?
Background
a. What Is Currently Required?
    In the May 26, 1999 rule revisions, EPA added a new quarterly QA 
test for flow monitors to part 75: the flow-to-load ratio test. Since 
promulgation, EPA has received many questions about the test 
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.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the flow-to-load test 
methodology by allowing the data exclusions listed in section 2.2.5(c) 
of appendix B to be taken 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 would clarify the issue of co-firing as 
it pertains to data exclusions. Units that co-fire different fuels as 
part of normal operation could claim flow-to-load test data exclusions 
for hours in which fuels were not co-fired, if the reference flow 
relative accuracy test audit (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 weeks to within 14 unit operating days.
    The proposal would also clarify the instructions for multiple stack 
configurations and allow the data to be analyzed 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.
c. What Changes Is EPA Finalizing?
    EPA received supportive comments from one commenter on the proposed 
revisions to the flow-to-load ratio test methodology (UARG). No adverse 
comments were received. Therefore, today's rule finalizes the changes 
for the reasons stated in the proposal.
5. What Special QA Provisions Are Finalized for Units That Do Not 
Produce Electrical Output or Steam Load?
Background
a. What Is Currently Required?
    Units subject to the monitoring and reporting requirements of part 
75 must account for their emissions on a continuous basis. Most units 
use 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 SO₂, NO_X, and 
CO₂ emissions from the affected unit. RATAs of gas and flow 
monitors are required for initial certification and either semiannually 
or annually thereafter.
    Section 6.5.1 of appendix A to part 75 requires that RATAs of gas 
monitors be done at a single "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

[[Page 40410]]

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.
    Under the NO_X SIP Call, some sources that do not produce 
electrical output or steam load, such as cement kilns or refinery 
process heaters, 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.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise section 6.5.2.1 of 
appendix A to part 75 by adding a method of establishing the proper 
operating levels at which to perform RATAs for units that do not 
produce electrical output or steam load (e.g., cement kilns and process 
heaters).
    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.
    Once the boundaries of the range of operation are established and 
the normal operating load level 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." The 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.
c. What Changes Is EPA Finalizing?
    EPA received adverse comments on the proposed approach to 
determining the range of operation, normal operating level, and flow 
RATA requirements for non-load-based units, i.e., units that do not 
produce electrical output or steam load. After careful consideration of 
these comments, EPA has modified the proposed approach. The requirement 
to define the range of operation and the low, mid, and high operating 
levels in terms of stack gas velocity (ft/sec) is being finalized in 
this action, with only one minor change: the owner or operator may use 
0.0 ft/sec as the "minimum potential velocity." However, 
EPA is not adopting the proposed requirement to perform a historical 
analysis of flow rate data to establish the "normal" 
operating level. Instead, today's final rule specifies that the normal 
operating level for a non-load-based unit is determined using sound 
engineering judgment and operating experience with the unit and 
process, and supported with documentation in the monitoring plan. In 
addition, new section 6.5.2(e) of today's rule allows the owner or 
operator of a non-load-based unit to obtain relief from three-load flow 
RATA testing, if an acceptable technical justification is provided in 
the monitoring plan. If the owner or operator can satisfactorily 
demonstrate that the process operates only at one level, then only 
single-level flow RATAs would be required for certification and on-
going quality assurance. If the process is demonstrated to operate at 
two distinct levels, then two-level flow RATAs would be required.
Discussion
    EPA received comments from only one commenter regarding the 
proposed method of determining range of operation, normal operating 
level, and the appropriate operating levels for flow RATAs (APCA). The 
commenter stated two objections to the proposed rule provisions: (1) 
that the "maximum potential velocity" approach is not 
applicable to cement kilns; and (2) that since cement kilns operate at 
one level, only single-level flow RATAs should be required.
    EPA does not agree with the commenter's claim that the concept of 
maximum potential velocity cannot be applied to a cement kiln. The 
Agency notes that the commenter did not explain why the proposed 
methodology will not work for cement kilns. EPA believes that for any 
non-load-based unit, an estimate of the highest stack gas velocity 
during normal operation should be easily obtainable, using EPA Method 2 
(see 40 CFR 60, Appendix A). However, EPA has reconsidered the proposed 
approach to determining the normal operating level and establishing the 
RATA levels for flow monitors installed on such units. For industrial 
processes, such as cement manufacturing, which often have only one 
distinct operating level, it may not be appropriate to require a 
historical data analysis to establish the normal operating level, or to 
require three-level flow RATAs to be performed.
    In view of these considerations, today's rule finalizes the 
requirement for non-load-based units to define the range of operation 
in terms of stack gas velocity as proposed. However, the velocity 
information is only used to define the operating range and the low, 
mid, and high operating levels. EPA is not adopting the proposed 
requirement for non-load-based units to determine the normal operating 
level by analyzing historical flow rate data. Instead, today's rule 
requires that the normal operating level be established using sound 
engineering judgment and process operating experience. Regarding the 
appropriate number of levels for flow RATAs, today's rule requires non-
load-based units to perform flow RATA testing at the same number of 
load levels as are specified for load-based units in section 2.3.1.3(c) 
of appendix B (i.e., three levels for certification, two levels for 
routine quality-assurance) unless the owner or operator submits a 
technical justification to the permitting authority with the hardcopy 
of the initial monitoring plan for the unit, demonstrating that the 
unit operates at only one level. Today's rule adds this

[[Page 40411]]

option in a new paragraph, (e), to section 6.5.2 of appendix A. The 
technical justification must include appropriate documentation and data 
to demonstrate that the process operates at only one level. If the 
justification is acceptable to the permitting authority, then only 
single-level flow RATAs would be required for initial certification, 
recertification, and on-going quality assurance. For non-load-based 
processes that operate at only two distinct levels, section 6.5.2(e) 
allows a similar justification to be submitted as an option to the 
three-level flow RATA testing.

D. Appendix D

1. What Changes to the Definitions of "Pipeline Natural 
Gas" and "Natural Gas" Are Finalized?
Background
a. What Is Currently Required?
    The definitions of "pipeline natural gas" and 
"natural gas" in Sec. 72.2 state that a gaseous 
fuel must meet a two-fold requirement to qualify as one of these fuels: 
the fuel must meet a hydrogen sulfide (H₂S) content limit 
(0.3 gr/100 scf for pipeline natural gas and 1.0 gr/100 scf for natural 
gas) and the H₂S must constitute at least 50 percent of the 
fuel's total sulfur content. Appendix D of part 75 does not explain how 
to comply with the second of these two requirements (i.e., the 
H₂S as a percentage of total sulfur). Further, industry 
members have expressed concern 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 H₂S and 0.3 gr/100 scf of total 
sulfur would not qualify as pipeline natural gas, because 
H₂S is less than 50 percent of the total sulfur content, but 
a fuel with three times more H₂S and twice as much total 
sulfur (0.3 gr/100 scf of H₂S 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 over the definitions of 
pipeline natural gas and natural gas, EPA issued interim guidance on 
June 12, 2000, discussing how sources could demonstrate compliance with 
the existing definitions (see Docket A-2000-33, Item 
IV-A-5). As explained in the guidance, through its 
authority under Sec. 75.66, EPA would allow owners or operators 
to comply by meeting a total sulfur limit (0.6 gr/100 scf for pipeline 
natural gas or 2.0 gr/100 scf for natural gas), in lieu of documenting 
that H₂S constitutes at least 50 percent of the total sulfur 
content.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the definitions of 
"pipeline natural gas" and "natural gas" in 
Sec. 72.2. All references to H₂S content would be 
removed and these fuels would be defined in terms of total sulfur 
content. The proposed total sulfur content values would be 0.5 gr/100 
scf for pipeline natural gas and 20.0 gr/100 scf for natural gas. The 
value of 20.0 gr/100 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.
    For fuels that qualify as pipeline natural gas, a default 
SO₂ emission rate of 0.0006 lb/mmBtu would be used to 
quantify SO₂ emissions, and for fuels that qualify as 
natural gas, a default SO₂ emission rate would be calculated 
based on Equation D-1h in appendix D. Equation D-1h would 
be revised and based upon the total sulfur content of the fuel, rather 
than the H₂S content.
c. What Changes Is EPA Finalizing?
    EPA received no adverse comments on the proposed revisions to the 
definitions of pipeline natural gas and natural gas. Therefore, today's 
rule finalizes the revised definitions as proposed.
Discussion
    EPA received comments from four commenters on the proposed 
revisions to the definitions of pipeline natural gas and natural gas 
(Class of '85, XCEL Energy, Clean Energy Group, UARG). All four 
commenters favored the proposed changes. One commenter noted that 
eliminating the hydrogen sulfide content limit would make the use of 
appendix D more attractive and would reduce the risk of unintentional 
violations of the monitoring requirements (Class of '85). In view 
of these supportive comments, EPA finalizes the proposed definitions of 
pipeline natural gas and natural gas without modification.
2. How Does Today's Rule Change the Method by Which a Gaseous Fuel 
Qualifies As "Pipeline Natural Gas" or "Natural 
Gas"?
Background
a. What Is Currently Required?
    The part 75 requirements for demonstrating that a particular 
gaseous fuel qualifies as pipeline natural gas or natural gas are found 
in sections 2.3.1.4 and 2.3.2.4 of appendix D. Compliance with the 
hydrogen sulfide content limit must be documented through one of five 
sources of information: (1) a fuel purchase or pipeline transportation 
contract; (2) vendor certification based on fuel sampling; (3) one year 
of monthly sampling; (4) one year of sampling each shipment or lot of 
fuel (for fuels delivered in shipments or lots); or (5) a demonstration 
consisting of 720 hours of sampling.
b. What Changes Were Proposed?
    As discussed in the previous question, on June 13, 2001, EPA 
proposed revising the definitions of pipeline natural gas and natural 
gas by removing the specified limits on the hydrogen sulfide content of 
the fuel and replacing them with limits on total sulfur content.
    EPA also proposed revisions to sections 2.3.1.4 and 2.3.2.4 of 
appendix D, which would change the way of documenting that a fuel 
qualifies as pipeline natural gas or natural gas. An initial compliance 
demonstration and periodic sampling of the total sulfur content of the 
fuel would be required. Initial compliance with the total sulfur limit 
would be documented either: (1) using a fuel purchase or pipeline 
transportation contract; or (2) using the results of all available fuel 
sampling results for the previous 12 months; or (3) using the results 
of a 720-hour demonstration; or (4) by obtaining and analyzing a sample 
of the fuel in the absence of a contract or historical fuel sampling 
data. Once a fuel initially qualified as pipeline natural gas or 
natural gas, periodic, on-going sampling for total sulfur content would 
be required. The proposed sampling frequency was semiannual and 
whenever "it is reasonable to believe that the fuel composition 
has changed significantly."
c. What Changes Is EPA Finalizing?
    EPA received numerous comments on both the proposed method by which 
a fuel qualifies as pipeline natural gas or natural gas and the 
proposed semiannual total sulfur sampling requirement. In view of the 
comments, EPA has modified these rule provisions. In today's rule, 
revised sections 2.3.1.4 and 2.3.2.4 of appendix D specify three 
methods by which a fuel may initially qualify as pipeline natural gas 
or natural gas: (1) by a fuel contract or tariff sheet with a maximum 
total sulfur specification that meets the definition of pipeline 
natural gas or natural gas; (2) based on historical fuel sampling and 
analysis data from the previous twelve months; or (3) in the absence of 
a satisfactory contract specification or historical sampling data, by 
obtaining a sample (or samples) of the fuel. For a

[[Page 40412]]

fuel that qualifies using a contract or tariff sheet specification, no 
additional on-going sampling of the total sulfur content is required, 
provided that the contract or tariff sheet is current, valid, and 
representative of the fuel combusted in the unit. For a fuel that 
initially qualifies as pipeline natural gas or natural gas based on 
fuel sampling and analysis, total sulfur sampling is required annually 
and whenever the fuel supply changes. The annual total sulfur sampling 
requirement has an effective date of January 1, 2003.
Discussion
    One commenter supported the proposed provision to allow a fuel to 
initially qualify as pipeline natural gas or natural gas based on a 
single fuel sample, and also supported the proposed semiannual total 
sulfur sampling requirement (Reliant). Another commenter expressed 
concern that for sources using the historical fuel sampling option, the 
language requiring that "all available fuel samples" from 
the past twelve months be used could require an exhaustive search of 
all possible sources of sample results and might lead to allegations 
that a source had excluded relevant samples (UARG). The commenter 
suggested that EPA should consider using alternate language, such as 
"representative fuel samples from the past twelve months", 
and that the Agency should also allow averaging of sample results. The 
commenter also stated that if a source has followed EPA's June 12, 2000 
guidance and has obtained the total sulfur sample(s) to document that 
the fuel being combusted qualifies as pipeline natural gas or natural 
gas, re-qualification is unnecessary and the source should only be 
subject to the on-going semiannual fuel sampling requirements.
    Three commenters objected to the proposed requirement to sample the 
total sulfur content of pipeline natural gas and natural gas 
semiannually (UARG, Class of '85, XCEL Energy). One of these commenters 
suggested that annual, rather than semiannual, sampling would be more 
appropriate, and that for sources relying on a contract specification, 
the on-going sampling should not be required at all (UARG). The other 
two commenters recommended deleting the semiannual sampling requirement 
and requiring re-sampling only if the fuel supply changes (Class of 
'85, XCEL Energy). Several commenters stated that EPA should 
allow immediate re-sampling to be performed if the results of a 
periodic sulfur sample analysis are believed to be anomalous or suspect 
(Class of '85, XCEL Energy, Machaver).
    After considering these comments, EPA has revised both the 
requirements for a fuel to initially qualify as pipeline natural gas or 
natural gas, and the on-going total sulfur sampling requirements. In 
today's rule, revised sections 2.3.1.4 and 2.3.2.4 of appendix D 
provide three methods by which a fuel may qualify: (1) By a total 
sulfur specification in a fuel contract or tariff sheet; (2) based on 
historical fuel sampling data from the previous twelve months; or (3) 
in the absence of a contract specification or historical sampling data, 
a sample of the fuel's total sulfur content must be obtained and 
analyzed. Note that EPA has removed the fourth option of performing the 
720-hour demonstration described in section 2.3.6 of appendix D to 
qualify, believing it to be unnecessary in light of the third option 
allowing use of a sample. The 720-hour demonstration has been reserved 
for characterizing the sulfur content of gaseous fuels other than 
pipeline natural gas and natural gas.
    Today's rule states that when the owner or operator relies on the 
specifications in a fuel contract or tariff sheet for a fuel to 
initially qualify as pipeline natural gas or natural gas, no initial or 
on-going sampling of the total sulfur content is required, provided 
that the contract or tariff sheet is current, valid, and representative 
of the fuel combusted in the unit. For a fuel that initially qualifies 
as pipeline natural gas or natural gas based on fuel sampling and 
analysis, total sulfur sampling is required annually and whenever the 
fuel supply changes. The annual total sulfur sampling requirement has 
an effective date of January 1, 2003.
    EPA believes that most sources are likely to use fuel sampling to 
demonstrate that the fuel qualifies as pipeline natural gas or natural 
gas, rather than relying on contract specifications. This is because 
the maximum total sulfur content specified in most contracts for 
transmitting pipeline natural gas, and under most tariffs established 
with the Federal Energy Regulatory Commission, is 20.0 gr per 100 scf, 
whereas the actual total sulfur content of natural gas is generally 10 
to 100 times lower. In the absence of actual fuel sampling data, Table 
D-5 in appendix D requires the maximum total sulfur content 
specified in the contract or tariff to be used to calculate the default 
SO₂ emission rate. Therefore, EPA believes that most sources 
combusting natural gas will elect to perform fuel sampling, rather than 
using the specifications in a fuel contract or tariff sheet, in order 
to avoid significantly overestimating SO₂ emissions.
    The final rule further states that when historical fuel sampling 
results are used to qualify, only those fuel samples taken by or 
provided to the owner or operator in the past twelve months need be 
considered. If multiple fuel samples are used to qualify, each sample 
must meet the applicable total sulfur limit. Also, if a single fuel 
supply serves many affected units, it is not necessary to obtain a 
separate sample for each unit, provided that no other gaseous fuel is 
mixed with the fuel in transporting it from the sampling location to 
the affected units. For fuels that qualify as natural gas, if multiple 
samples are taken, the results may be averaged before using Equation 
D-1h to calculate the default emission rate.
    If the results of any required fuel sampling and analysis fail to 
demonstrate that a fuel qualifies as pipeline natural gas or natural 
gas, but the results are suspect or believed to be anomalous, the owner 
or operator may document the reasons for believing this in the 
monitoring plan and additional sampling may be initiated immediately. 
In such cases, at least three additional samples are required and each 
sample analysis must meet the applicable total sulfur limit for 
pipeline natural gas or natural gas.
    Finally, EPA notes that affected facilities currently relying on 
total sulfur samples obtained in accordance with the June 12, 2000 
guidance to meet the definition of pipeline natural gas or natural gas 
are not required to perform any additional sampling to re-qualify, 
provided that the fuel supply source has not changed since the samples 
were taken. These facilities are subject only to the on-going, annual 
total sulfur sampling requirement which takes effect in 2003.
3. How Does Today's Rule Change the Fuel Sampling and Data Reporting 
Requirements for Gaseous Fuels Other Than Pipeline Natural Gas and 
Natural Gas?
Background
a. What Is Currently Required?
    Appendix D of part 75 may be used for "other" gaseous 
fuels besides pipeline natural gas and natural gas. For these other 
gaseous fuels, appendix D does not allow SO₂ emissions to be 
quantified using a default SO₂ emission rate. Rather, hourly 
sampling of the total sulfur content of the fuel is required using 
manual sampling methods or an on-line gas chromatograph, although 
section 2.3.6 in appendix D provides a

[[Page 40413]]

720-hour demonstration procedure whereby some relief from hourly sulfur 
sampling can be obtained. The demonstration requires 720 hours of 
sampling to characterize the fuel's total sulfur content and 
variability. If the results of the demonstration show that the fuel has 
a low sulfur variability, then the owner or operator may sample the 
fuel's sulfur content daily instead of hourly.
b. What Changes Were Proposed?
    In the June 13, 2001 proposed rule, EPA proposed clarifying that 
the 720-hour demonstration procedure in section 2.3.6 of appendix D is 
optional and that it may be used to show that the sulfur content of a 
particular gaseous fuel is within the limits for pipeline natural gas 
or natural gas. However, the Agency received a significant comment on 
section 2.3.6, requesting that EPA allow the demonstration procedure to 
be used to determine default SO₂ emission factors for 
gaseous fuels such as refinery gas and producer gas, so that units 
burning these fuels would be able to obtain relief from the hourly or 
daily sulfur sampling requirements.
c. What Changes Is EPA Finalizing?
    EPA believes that the commenter's suggestion has merit, and has 
incorporated it into the final rule. Today's rule conditionally allows 
the owner or operator of an Acid Rain Program unit that combusts a 
gaseous fuel other than pipeline natural gas or natural gas to 
determine a fuel-specific default SO₂ emission rate using 
the results of the 720-hour demonstration in section 2.3.6 of appendix 
D. The default emission rate could be used in conjunction with the 
hourly heat input rate to quantify hourly SO₂ emissions in 
the same manner as is done for pipeline natural gas or natural gas. The 
only exception to this would be if the results of the 720-hour 
demonstration indicate that the gaseous fuel has both a high sulfur 
content and high sulfur variability (i.e., greater than 5.0 grains per 
100 scf, standard deviation). In that case, the more rigorous hourly 
sulfur sampling would be required.
Discussion
    EPA received one comment on the proposed changes to section 2.3.6 
of appendix D (UARG). The commenter requested that EPA add language to 
section 2.3.6 stating that for "other" low-sulfur gaseous 
fuels (such as producer gas, refinery gas, and landfill gas), the 
results of the 720-hour demonstration in section 2.3.6 may be used to 
determine a fuel-specific default SO₂ emission rate such as 
is determined for natural gas by using Equation D-1h. The 
principal reason for this recommended rule revision would be to provide 
regulatory relief from the current appendix D requirement to perform 
either hourly or daily sulfur sampling for these "other" 
gaseous fuels.
    EPA finds the commenter's request to be reasonable and believes 
that the 720-hour demonstration is sufficiently representative to 
support the desired regulatory relief with little risk of 
underestimating SO₂ emissions. Therefore, today's rule adds 
the requested language to section 2.3.6 of appendix D. In the final 
rule, revised section 2.3.6 conditionally allows "other" 
gaseous fuels (e.g., refinery gas or producer gas) to use default 
SO₂ emission rates to quantify SO₂ mass emissions 
rather than performing daily or hourly sampling for total sulfur. If 
the 720-hour demonstration described in section 2.3.6 is performed for 
the gaseous fuel, the results of that demonstration may be used to 
determine a default SO₂ emission rate, provided that the 
fuel is not found to have both a high sulfur content (more than 20 
grains per 100 scf) and a high sulfur variability (more than 5 grains 
per 100 scf, standard deviation). If the fuel qualifies to use a 
default SO₂ emission rate, then Equation D-1h in 
appendix D may be used to calculate the emission rate in the same 
manner that a default emission rate would be calculated for natural 
gas. The exact value of the fuel's total sulfur content used to 
calculate the default emission rate depends on whether the fuel is 
found to have a low or high sulfur variability (i.e., variability with 
a standard deviation of greater than 5.0 grains per 100 scf) during the 
720-hour demonstration. If the sulfur variability is low, the 90th 
percentile value from the demonstration is used in the calculation. If 
the sulfur variability is high, the maximum value from the 
demonstration is used to calculate the default SO₂ emission 
rate.
    Today's rule requires periodic on-going total sulfur sampling for 
other gaseous fuels that use the demonstration in section 2.3.6 to 
determine a default SO2 emission rate. The required sampling frequency 
is annual. For reporting purposes, the default emission rate derived 
from the 720-hour demonstration is used unless a higher sulfur content 
is obtained in an annual sample, in which case the higher sampled value 
would be reported.
    The Agency notes that the 720-hour demonstration in section 2.3.6 
may also be used to derive fuel-specific default SO₂ 
emission rates for Acid Rain Program units seeking to qualify as low 
mass emissions units under Sec. 75.19 (see Docket 
A-2000-33, Item V-C-1 for further discussion).
4. What Changes to the Appendix D Missing Data Procedures Are 
Finalized?
Background
a. What Is Currently Required?
    Appendix D requires the owner or operator to report substitute data 
for any hour in which quality-assured fuel flow rate data is not 
obtained and whenever a sample of the fuel sulfur content, gross 
calorific value, or density has not been obtained and analyzed as 
required. The load-based missing data procedures for fuel flow rate are 
found in section 2.4 of appendix D. The appropriate substitute data 
values for fuel sulfur content, gross calorific value, and density are 
given in Table D-6.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the appendix D missing data 
procedures. The load-based fuel flow rate missing data procedures in 
section 2.4.2 would be clarified but not substantively changed. New 
fuel flow rate missing data procedures would be added for units that do 
not produce electrical output or steam load. The missing data 
requirements for the sulfur content of gaseous fuels in Table D-6 
would also be changed, as follows: (1) Substitute data values for 
pipeline natural gas and natural gas would be expressed in terms of the 
total sulfur content of the gas instead of the hydrogen sulfide 
content; (2) for pipeline natural gas, the substitute data value would 
be 0.002 lb/mmBtu; (3) for natural gas, the substitute data value would 
be an emission rate (in lb/mmBtu) calculated from Equation D-1h 
using the lesser of the maximum total sulfur content specified in the 
fuel contract or 1.5 times the highest total sulfur value from the 
previous year's samples; (4) 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; and (5) for gaseous 
fuels sampled hourly, the substitute data value would be the highest 
total sulfur content from the previous 720 hourly samples.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the revisions to the appendix D missing data 
procedures. The final rule provisions have been modified somewhat from 
the proposal to be consistent with changes that have been made to other 
sections of appendix D based on comments received. The fuel flow rate 
missing data

[[Page 40414]]

procedures for non-load-based units have also been simplified to make 
them easier to implement. EPA has provided additional time in the rule 
language from the effective date of today's rule for owners and 
operators to implement these new missing data routines (see Section V., 
Rule Implementation, of this preamble).
Discussion
    EPA received comments on the proposed revisions to the appendix D 
missing data routines from only one commenter (UARG). The commenter was 
generally supportive of the proposed changes to the gas sulfur content 
substitute data values in Table D-6 and to the missing data 
routines for fuel flow rate. However, the commenter expressed concern 
that the changes would require significant reprogramming of the data 
acquisition and handling system (DAHS) software and requested that EPA 
allow sufficient time to implement the new missing data routines.
    In view of the supportive comments received, the proposed revisions 
are finalized with only minor changes. These changes to the proposal 
are deemed necessary for purposes of consistency. Other sections of 
appendix D have been modified based on comments received, and some of 
the changes to those sections impact the missing data routines. The 
most significant change was made to the substitute data value for 
natural gas combustion. The proposed rule would have required the 
substitute data value to be the lesser of: (a) the maximum sulfur 
content specified in the fuel contract; or (b) 1.5 times the highest 
sulfur content from the previous year's samples. The final rule 
requires the substitute data value to be 1.5 times the default value of 
sulfur content which is in effect at the time of the missing data 
period. According to revised Table D-5, the default value 
"in effect" will be either the maximum sulfur content 
specified in the fuel contract or the sulfur content from the most 
recent sample. Since the required sampling frequency for natural gas is 
annual, only one sample is required each year. Thus, there is little 
difference in meaning between the proposed rule language, i.e., 
"highest sulfur content from the previous year's samples" 
and the final rule language, i.e., "sulfur content from the most 
recent sample."
    Today's rule finalizes the proposed fuel flow rate missing data 
routines both for load-based units and for units that do not produce 
electrical or steam load. The load-based provisions are finalized as 
proposed; however, for ease of implementation the proposed non-load-
based routines have been simplified. In the final rule, the substitute 
data value for non-load-based units is simply the arithmetic average of 
the quality-assured flow rates in a 720-hour lookback period. EPA is 
not finalizing the proposed option that would have allowed the data to 
be sorted into operating bins, nor the associated text in section 4 of 
appendix C. The Agency believes that separating fuel flow data into 
operating bins unnecessarily complicates the missing data routines. EPA 
expects that not finalizing this proposed missing data option will have 
little or no impact since, at present, there are no non-load-based oil 
and gas-fired units required to use part 75 monitoring. However, it is 
possible that such units may be included in a future program such as 
the Federal NO_X Budget Trading Program. Should the owners or 
operators of such units elect to use appendix D and decide that 
operational bins are needed for fuel flow rate missing data purposes, 
EPA will consider allowing that missing data approach through the 
petition process under Sec. 75.66.

E. Other Highlights and Changes

1. What Changes to the Compliance Dates and Timelines for Monitor 
Certification in Sec. 75.4 Are Finalized in Today's Rule?
Background
a. What Is Currently Required?
    Part 75 specifies different monitor certification timelines in 
Sec. 75.4 for new units, new 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 
provides greater flexibility.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to harmonize all of the timelines 
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, section 126 final rule in 
order to make the certification timelines in parts 75 and 97 
consistent.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the proposed changes to the certification 
timelines in parts 75 with one exception. For newly-affected Acid Rain 
Program units under Sec. 75.4(c), the certification timeline 
would begin with the first hour of operation of the unit after the date 
on which it becomes an Acid Rain-affected unit, rather than the first 
hour after the unit becomes Acid Rain-affected.
Discussion
    EPA received numerous comments on the proposed changes to the 
certification timelines in Sec. 75.4 (Reliant, Clean Energy 
Group, Dominion, UARG, Class of '85, Dynegy). All of the commenters 
were supportive of the proposed revisions. However, one commenter 
requested that Sec. 75.4(c) be revised further (Dominion). The 
commenter recommended that the timeline for newly-affected Acid Rain 
Program units be modified so that the "clock" starts with 
the first hour of commercial operation of the unit after it becomes 
affected, rather than starting from the date and hour on which the unit 
becomes affected. The commenter indicated that this would provide the 
utility with the option of not operating a newly-acquired unit, thereby 
allowing time to acquire the necessary CEMS equipment. EPA agrees that 
this added flexibility in the certification timeline for newly-affected 
units is desirable and incorporates the commenter's suggestion into the 
final rule.

[[Page 40415]]

2. Does Today's Rule Change the Way in Which Unit and Stack Operating 
Hours Are Counted?
Background
 a. What Is Currently Required?
    Part 75 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 not 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.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to add two new definitions, 
"cumulative stack operating hours" and "cumulative 
unit operating hours", 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. 
These proposed changes would effectively remove the requirement to 
count partial operating hours as full hours when determining the source 
operating time and the length of the grace period.
c. What Changes Is EPA Finalizing?
    EPA is finalizing neither of the proposed definitions of 
"cumulative stack operating hours" and "cumulative 
unit operating hours" nor the proposed changes to the way in 
which unit and stack operating hours are counted.
Discussion
    EPA received input from four commenters on the proposed changes to 
the method of counting unit and stack operating hours (Class of '85, 
Dynegy, UARG, XCEL Energy). None of the commenters supported the 
changes without reservation. All of them indicated that EPA should make 
the changes optional, not mandatory. All of the commenters stated that 
the changes would require significant, potentially costly changes to 
the DAHS software. The commenters also noted that for many utilities, 
the increase in rule flexibility associated with the changes would not 
be great enough to justify the expense.
    In the absence of fully supportive comments, EPA has decided not to 
adopt the proposed revisions. The Agency considered incorporating the 
commenters' suggestion to allow two options for calculating source 
operating time, i.e., one based on unit operating hours and one based 
on "cumulative" unit operating hours. However, EPA rejected 
this approach because it would seriously complicate program oversight. 
It also would require significant re-programming of EPA's data checking 
software and would require structural changes to several EDR record 
types. In this case, the Agency concludes that the relatively small 
benefit of allowing a second method of calculating source operating 
time does not justify the associated cost.
3. Does Today's Rule Change the Notification Requirements for Monitor 
Certifications and Recertifications?
Backround
    For the initial certification of continuous monitoring systems, 
part 75 requires the owner or operator to provide a minimum of 45 days 
advance notice before the first date of scheduled testing. For 
recertifications, at least 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).
    On June 13, 2001, EPA proposed revising Sec. 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. EPA believed the existing 7-day 
notice for partial recertifications provided too little time for State 
and local agency personnel and EPA personnel to schedule site visits to 
observe the recertification testing. Conversely, the Agency believed 
that 45 days notice was too far in advance of the testing. 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.
    Based on comments received, EPA is finalizing the 21-day 
certification test notification requirement as proposed, but has 
modified the proposed recertification test notification provisions. 
Today's rule makes a clearer distinction between full and partial 
recertifications and the notification requirements for each type. The 
final rule reduces the notification requirement for full 
recertifications from 45 to 21 days as proposed, but retains the 7-day 
advance notice requirement for partial recertifications. An emergency 
provision for unplanned full recertifications has also been added to 
Sec. 75.61(a)(1)(i).
Discussion
    EPA received comments from five commenters on the proposed changes 
to the certification and recertification test notification requirements 
(Dominion, Dynegy, UARG, Class of '85, ESC). The commenters did not 
object to reducing the test notification time for initial 
certifications from 45 to 21 days. However, four of the commenters 
objected to the proposal to require 21 days advance notice for 
recertifications (Dominion, Dynegy, UARG, ESC), and the fifth commenter 
objected to the 7-day notification requirement when the scheduled RATA 
is performed on a different date (Class of '85). The commenters 
perceive the 21-day notification requirement for recertifications as 
being an increase from the 7-day requirement of the current rule. For 
reasons discussed in greater detail in the "Response to 
Comments" document supporting this rulemaking (see Docket No. 
A-2000-33, Item V-C-1), this perception is not 
entirely correct. The proposed 21-day notification requirement 
represents an increase in notification time only for partial 
recertifications (where a full battery of tests is not required). For 
full recertifications, where all of the tests are required, 21 days 
notice actually is a reduction from the 45-day notification requirement 
of the current rule.
    The commenters' main objection to the 21-day notification 
requirement for recertifications centers around emergency (unplanned) 
events that require recertification. The commenters expressed concern 
that requiring such a long advance notice would require sources in 
emergency situations to postpone testing in order to give observers the 
opportunity to schedule site visits. The commenters stated that this 
could result in sources having to use the missing data routines for 
long periods of time which is inconsistent with the part 75 goal of 
keeping monitors operating and reducing missing data episodes.
    After consideration of these comments, EPA is finalizing the 21-day 
test notification requirement for initial certifications and for full

[[Page 40416]]

recertifications. The text of Sec. 75.61(a)(1)(i) is revised to 
be consistent with Sec. 75.20(b)(2) and to make it clear that 
the 21-day requirement applies to full recertifications as well as 
initial certifications. A typographical error in Sec. 75.20(b) 
is also corrected. The proposed 21-day notification for partial 
recertifications is not adopted, and the 7-day requirement, with the 
associated emergency provision, is retained.
    To address the commenters' concern about emergency 
recertifications, Sec. 75.61(a)(1)(i) of today's rule provides 
an emergency provision for unplanned events beyond the source 
operator's control which require a full battery of recertification 
tests to be performed. The emergency provision is the same as the one 
in Sec. 75.61(a)(1)(ii) for partial recertifications.
4. Does Today's Rule Affect the Way in Which Emissions Are Monitored 
and Reported for Units With Bypass 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 allows the maximum potential SO₂ 
concentration to be reported during the malfunction in lieu of 
installing monitors on the bypass stack. For NO_X, 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.
    On June 13, 2001, EPA proposed clarified and expanded instructions 
for SO₂ and NO_X monitoring of multiple and bypass 
stack configurations in Sec. 75.16(c) and 75.17(c), and 
in Sec. 75.72(c) and (d). EPA proposed a new provision to 
Sec. 75.17(c) and 75.72(c) for configurations consisting 
of a main stack and a bypass stack, allowing the maximum potential 
NO_X emission rate to be reported when the bypass stack is 
used.
    EPA also proposed revisions to the language in 
Sec. 75.16(c)(3) which restricts the reporting of the maximum 
potential SO₂ concentration (MPC) to emergency situations in 
which the flue gas desulfurization (FGD) system is bypassed. Proposed 
Sec. 75.16(c)(3) 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.
    Today's rule finalizes the proposed bypass stack monitoring and 
reporting revisions with minor editorial changes.
Discussion
    Two commenters supported the proposed revisions to the bypass stack 
monitoring provisions (UARG, Reliant). However, one of the commenters 
objected to the proposed language in Sec. 75.16(c) and 
75.17(c) addressing the reporting of parameters other than 
SO₂ or NO_X during bypass hours, stating that the 
proposed language "creates confusion and conflict" (UARG).
    After consideration of these comments, EPA is finalizing the bypass 
stack monitoring provisions as proposed, except that the references in 
Sec. 75.16(c) and 75.17(c) to the reporting of other 
parameters, such as CO₂, are not adopted because EPA 
believes that these requirements are adequately addressed in other 
sections of the rule and do not need to be re-stated here.
5. What Other Noteworthy Provisions Are Finalized in Today's Rule?
    EPA notes that no negative comment was received on the following 
significant revisions to part 75 that are finalized for the reasons 
stated in the proposed rule:
    · The proposal to remove the restriction in section 
2.1.2 of appendix D prohibiting apportionment of measured hourly heat 
input at a common pipe to the individual units (for units using the 
provisions of subpart H of part 75 to monitor NO_X mass 
emissions) is finalized. Common pipe heat input apportionment is now 
allowed for subpart H units, provided that the units served by the pipe 
are all affected units with similar efficiencies (e.g., all boilers or 
all turbines).
    · The proposed revisions to the appendix E missing data 
procedures are finalized.
    · The proposed revisions to appendix E, section 2.2, 
requiring retesting once every 5 years (20 calendar quarters) and 
removing the requirement to retest every 3,000 operating hours are 
finalized.
    · The proposal to expand the use of Equation G-4 
in appendix G to oil-fired units is finalized.

F. Streamlining Changes

Background
    A number of rule sections in part 75 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.
    On June 13, 2001, EPA proposed streamlining 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 Agency proposed to remove from part 75 all of the rule sections 
that expired on April 1, 2000, and all textual references to those 
sections. This includes the recordkeeping and reporting sections, 
Sec. 75.54, 75.55, and 75.56; the monitoring plan 
provisions in Sec. 75.53(c) and (d); and the CO₂ 
missing data provisions in Sec. 75.35(c).
    EPA also proposed removing rule sections that only applied to Phase 
I Acid Rain Program units and are now inapplicable, and to remove all 
textual references to those sections. For instance, 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. The 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.
    Today's rule finalizes the streamlining changes as proposed. EPA 
has prepared a technical support document (see Docket No. 
A-2000-33, Item IV-A-9) that identifies in 
tabular form all of the streamlining changes made to part 75.
Discussion
    EPA received comments from only one commenter on the proposed 
streamlining changes to part 75 (UARG). The commenter agreed that the 
cited rule provisions are obsolete and did not object to their removal. 
Therefore, EPA finalizes the changes as proposed.

V. Rule Implementation

    This final rule becomes effective July 12, 2002. However, EPA is 
aware that while some affected sources may choose to take advantage of 
options provided immediately, others will require more time for 
implementation. Therefore, EPA has specified in this final rule where 
additional time is permitted for

[[Page 40417]]

full compliance with new mandatory requirements.
    The rule provisions that provide alternative compliance dates are 
as follows: Appendix A paragraph 2.1.2.1(a); Appendix D Table D-6 
under Gas Total Sulfur Content; and Appendix E paragraph 2.5.2.
    EPA is aware that some non-load based units are required under 
their State's SIP to start monitoring NO_X mass emissions 
according to part 75 in the 2002 ozone season. EPA will continue to 
work with the affected sources and the State to resolve any conflicts 
imposed on the sources by the timing of today's rule.
    Some aspects of the final rule that will require attention concern 
reporting requirements and mechanisms. While EPA is prepared to accept 
electronic data reports in the proscribed format, regulated sources 
will require time to review the final rule and make any adjustments or 
changes in software that may result. With this in mind, EPA is updating 
the EDR version 2.1 Instructions to accompany this final rule. EPA has 
identified in the rule language any deadlines for compliance that are 
different from the effective date of this rule, as applicable. If you 
have questions regarding the implementation of this final rule, consult 
the person listed in the preceding FOR FURTHER INFORMATION CONTACT 
section of this preamble.

VI. Regulatory Assessment Requirements

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Agency 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 final rule is not expected to have an annual effect on the 
economy of $100 million or more. It has been determined that this rule 
is not a "significant regulatory action" under the terms of 
Executive Order 12866 and it is therefore not subject to OMB review.

B. 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 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.
    Today's rule is not expected to result in expenditures of $100 
million or more for State, local, and tribal governments, in the 
aggregate, or the private sector in any one year and, as such, is not 
subject to sections 202 and 205 of the UMRA. As discussed in section 
III., above, EPA will continue to use its outreach efforts related to 
part 75 implementation, including guidance documents and a policy 
manual that is updated regularly, to inform, educate, and advise all 
potentially impacted governments about compliance with part 75.

C. Paperwork Reduction Act

    The Office of Management and Budget (OMB) has approved the 
information collection requirements contained in this rule under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et. seq. and 
has assigned OMB control numbers 2060-0258 and 2060-0445.
    The information collection requirements in 40 CFR parts 72 and 75 
affect two EPA programs, the Acid Rain Program and the Federal 
NO_X 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 and 75. First, the 
Acid Rain Program ICR (ICR 1633.12, OMB No. 2060-0258) addresses 
the costs for units affected by the Acid Rain Program. The 
NO_X SIP Call ICR (ICR 1857.02, OMB No. 2060-0445) 
addresses the costs, including NO_X mass monitoring costs, by 
both Acid Rain Program (ARP) units and non-ARP units in the 
NO_X Budget Trading Program.
    Most of the changes associated with this rulemaking provide 
additional flexibilities to existing 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 changes finalized in parts 72 and 
75, 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 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 rule 
revisions to the LME section clarify how the rule applies to non-ARP 
SIP Call units that use part 75 for NO_X mass monitoring. 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 from 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

[[Page 40418]]

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 and applicability of LME for Subpart
 H monitoring
------------------------------------------------------------------------

    Although not indicated in Table 1, there are two primary ways in 
which the parts 72 and 75 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_X SIP 
Call will experience less burden as a consequence of the numerous 
clarifications, the specific changes to address NO_X mass 
monitoring issues, and the removal of outdated sections. Taken as a 
whole, EPA does not believe that the regulatory review burdens will be 
significant.
    The second type of burden or cost increase would be associated with 
any required 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 rule revisions that could 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. As noted in Section V., Rule 
Implementation, of this preamble, sources regulated under part 75 will 
have additional time to comply with certain provisions. Consequently, 
the expected impact associated with DAHS changes is also expected to be 
minimal.
    In the proposed rule, the Agency specifically requested comment on 
its assessment of information burden imposed by these requirements and 
received no comments on the subject. Burden means the total time, 
effort, or financial resources expended by persons to generate, 
maintain, retain, or disclose or provide information to or for a 
Federal agency. This includes the time needed to review instructions; 
develop, acquire, install, and utilize technology and systems for the 
purpose of collecting, validating, and verifying information; process 
and maintain information and disclose and provide information; adjust 
the existing ways to comply with any previously applicable instructions 
and requirements; train personnel to respond to a collection of 
information; search existing data sources; complete and review the 
collection of information; and transmit or otherwise disclose the 
information.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a valid 
OMB control number. The OMB control numbers for EPA's regulations are 
listed in 40 CFR part 9 and 48 CFR chapter 15.

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

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    After considering the economic impacts of today's final rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. In 
determining whether a rule has a significant economic impact on a 
substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives "which minimize any 
significant economic impact of the proposed rule on small 
entities." 5 U.S.C. 603 and 604. Thus, an agency may certify that 
a rule will not have a significant economic impact on a substantial 
number of small entities if the rule relieves regulatory burden, or 
otherwise has a positive effect on the small entities subject to the 
rule. Today's final action adds flexibility to the existing procedures 
for monitoring and reporting and makes other streamlining improvements 
and clarifications to the existing regulations. The EPA has therefore 
concluded that today's final rule will have no adverse impacts on small 
entities and may relieve burden in some cases.

E. National Technology Transfer and Advancement Act

    As noted in the proposed rule, section 12(d) of the National 
Technology Transfer and Advancement Act of 1995 ("NTTAA"), 
Public Law No. 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, and business 
practices) that are developed or

[[Page 40419]]

adopted by voluntary consensus standards bodies. The NTTAA directs EPA 
to provide Congress, through OMB, explanations when the Agency decides 
not to use available and applicable voluntary consensus standards.
    This rulemaking involves environmental monitoring or measurement. 
Consistent with the Agency's Performance Based Measurement System 
("PBMS"), part 75 sets forth criteria that allow the use of 
alternative methods to the ones identified in part 75. The PBMS 
approach is intended to be more flexible and cost effective for the 
regulated community; it is also intended to encourage innovation in 
analytical technology and improved data quality.
    EPA specifically requested public comment on any other voluntary 
consensus standards which may be appropriate for the part 75 rule 
revisions and no such comments were received. The EPA is not precluding 
the use of any method, whether it constitutes a voluntary consensus 
standard or not, as long as it meets the performance criteria 
specified; however, any alternative methods must be approved through 
the petition process under Sec. 75.66(c) before they may be 
used under part 75.

F. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    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: (1) Is determined to be 
"economically significant" as defined under Executive Order 
12866, and (2) concerns an environmental health or safety risk that EPA 
has reason to believe may have a disproportionate effect on children. 
If the regulatory action meets both criteria, the Agency must evaluate 
the environmental health or safety effects of the planned rule on 
children, and explain why the planned regulation is preferable to other 
potentially effective and reasonably feasible alternatives considered 
by the Agency.
    Today's rule is not subject to Executive Order 13045 because it is 
not economically significant as defined in Executive Order 12866, and 
because the Agency does not have reason to believe the environmental 
health or safety risks addressed by this action present a 
disproportionate risk to children.

G. Executive Order 13132: Federalism

    Executive Order 13132, entitled "Federalism" 
(64 FR 43255, August 10, 1999), requires EPA to develop an accountable process 
to ensure "meaningful and timely input by State and local 
officials in the development of regulatory policies that have 
federalism implications." "Policies that have federalism 
implications" is defined in the Executive Order to include 
regulations that have "substantial direct effects on the States, 
on the relationship between the national government and the States, or 
on the distribution of power and responsibilities among the various 
levels of government."
    Today's action does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. This final rule 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. Thus, Executive Order 13132 does 
not apply to this rule.
    As discussed above in Section III. and in the spirit of Executive 
Order 13132, and consistent with EPA policy to promote communications 
between EPA and State and local governments, EPA specifically worked 
with and solicited comment on the proposed rule from State and local 
officials.

H. Executive Order 13175: Consultation and Coordination with Indian 
Tribal Governments

    Executive Order 13175, entitled "Consultation and 
Coordination with Indian Tribal Governments" 
(59 FR 22951, 
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 final 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.
    Moreover, as discussed above in Section III. and in the spirit of 
Executive Order 13175, and consistent with EPA policy to promote 
communications between EPA and tribal governments, EPA specifically 
solicited comment on the proposed rule from tribal officials.

I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This rule is not a "significant energy action" as 
defined in Executive Order 13211, "Actions Concerning Regulations 
That Significantly Affect Energy Supply, Distribution, or Use" 
(66 FR 28355, May 22, 2001) because it is not likely to have a 
significant adverse effect on the supply, distribution, or use of 
energy. Further, we have concluded that this rule is not likely to have 
any adverse energy effects.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. This rule will take 
affect July 12, 2002.

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, NO_X Budget Trading 
Program, Reporting and recordkeeping requirements, Sulfur oxides.

40 CFR Part 75

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Carbon dioxide, Continuous emission 
monitoring (CEM), Electric generating units (EGUs), Electric utilities, 
Nitrogen oxides, Non-electric generating units (Non-EGUs), Non-load 
based units, NO_X Budget Trading Program, Reporting and 
recordkeeping requirements, Subpart H, Sulfur oxides.

[[Page 40420]]

    Dated: May 1, 2002.
Christine Todd Whitman,
Administrator.

    For the reasons set out in the preamble, title 40 chapter I of the 
Code of Federal Regulations is 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", "Low 
mass emissions unit", "Missing data period", 
"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 removing the words "or more" at the end 
of the definition;
    i. Removing the definition of "Heat input" and adding 
in its place a new definition "Heat input rate";
    j. Removing the definition of "Hour before and after" 
and adding in its place a new definition of "Hour before and Hour 
after";
    k. Removing the definition of "Maximum potential 
NO_X emission rate" and adding in its place 
"Maximum potential NO_X emission rate or MER";
    l. Removing the definition of "Maximum rated hourly heat 
input" and adding in its place the definition for "Maximum 
rated hourly heat input rate";
    m. In the definition for "monitor accuracy" by removing 
the words "or by one of its component parts";
    n. In the definition of "Natural gas" by revising the 
second sentence, and by removing the word "meet" and 
revising the "%" symbol to read "percent" in 
the third sentence;
    o. In the definition of "Peaking unit" by adding a new 
paragraph (4);
    p. 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";
    q. Adding new definitions for "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".
    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 SO₂, NO_X, or 
CO₂ 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 
SO₂ pollutant concentration monitor and an automated DAHS. 
An SO₂ monitoring system provides a permanent, continuous 
record of SO₂ 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_X) emission rate (or 
NO_X-diluent) monitoring system, consisting of a 
NO_X pollutant concentration monitor, a diluent gas 
(CO₂ or O₂) monitor, and an automated DAHS. A 
NO_X-diluent monitoring system provides a permanent, 
continuous record of: NO_X concentration in units of parts 
per million (ppm), diluent gas concentration in units of percent 
O₂ or CO₂ (% O₂ or CO₂), 
and NO_X emission rate in units of pounds per million British 
thermal units (lb/mmBtu);
    (4) A nitrogen oxides concentration monitoring system, consisting 
of a NO_X pollutant concentration monitor and an automated 
DAHS. A NO_X concentration monitoring system provides a 
permanent, continuous record of NO_X 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_X mass 
emissions (in lb/hr) under subpart H of part 75 of this chapter;
    (5) A carbon dioxide monitoring system, consisting of a 
CO₂ pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO₂ 
concentration is derived) and the automated DAHS. A carbon dioxide 
monitoring system provides a permanent, continuous record of 
CO₂ emissions in units of percent CO₂ (% 
CO₂); and
    (6) 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 H₂O (% H₂O)
* * * * *
    Diluent cap value means a default value of percent CO₂ 
or O₂ which may be used to calculate the hourly 
NO_X emission rate, CO₂ mass emission rate, or 
heat input rate, when the measured hourly average percent 
CO₂ is below the default value or when the measured hourly 
average percent O₂ is above the default value. The diluent 
cap values for boilers are 5.0 percent CO₂ and 14.0 percent 
O₂. For combustion turbines, the diluent cap values are 1.0 
percent CO₂ and 19.0 percent O₂.
* * * * *
     Emergency fuel means either:
    (1) * * *
    (2) For purposes of the requirement for stack testing for an 
excepted

[[Page 40421]]

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 SO₂ or CO₂ concentration, hourly flow 
rate, hourly NO_X concentration, hourly moisture, hourly 
O₂ concentration, or hourly NO_X 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.
* * * * *
    Low mass emissions unit means an affected unit that is "gas-
fired" or "oil-fired" (as defined in this section), 
and that qualifies to use the low mass emissions excepted methodology 
in Sec. 75.19 of this chapter.
* * * * *
    Maximum potential NO_X 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 (MPC), 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 O₂) or the 
minimum carbon dioxide concentration (in percent CO₂) 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 O₂ or minimum 
CO₂ concentration to calculate the MER. As a second 
alternative, when the NO_X MPC is determined from emission 
test results or from historical CEM data, as described in section 
2.1.2.1 of appendix A to part 75 of this chapter, quality-assured 
diluent gas (i.e., O₂ or CO₂) data recorded 
concurrently with the MPC may be used to calculate the MER. For the 
purposes of Sec. 75.4(f), 75.19(b)(3), and 75.33(c)(7) in 
part 75 of this chapter and section 2.5 in appendix E to part 75 of 
this chapter, the MER is specific to the type of fuel combusted in the 
unit.
    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.
* * * * *
    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 means * * * Natural gas contains 20.0 grains or less of 
total sulfur per 100 standard cubic feet. * * *
* * * * *
    Peaking unit means: * * *
    (4) A unit required to comply with the provisions of subpart H of 
part 75 of this chapter, under a State or Federal NO_X mass 
emissions reduction program, may, pursuant to Sec. 75.74(c)(11) 
in part 75 of this chapter, qualify as a peaking unit on an ozone 
season basis rather than an annual basis, if the owner or operator 
reports NO_X mass emissions and heat input data only during 
the ozone season.
* * * * *
    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, 7651k, and 7651k note.

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 paragraphs (b)(2) and (c)(2) by revising the words "Not 
later than 90" to read "The earlier of 90 unit operating 
days or 180 calendar", and, in paragraph (c)(2), by revising the 
word "becomes" to read "first operates after 
becoming";
    b. 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

[[Page 40422]]

removing the words "of the affected unit" after the words 
"recommences commercial operation";
    c. Revising paragraphs (d)(1), (f) introductory text, (f)(1), 
(i)(2) and (i)(3);
    d. In paragraph (e) introductory text, by revising the words 
"90 calendar days" to read "90 unit operating days or 
180 calendar days (whichever occurs first)", by removing the word 
"or" in each instance that it occurs between "flue, 
or flue gas" or "flue or flue gas", by adding a comma 
between the words "flue" and "flue gas" in the 
second sentence, and by adding "or add-on NO_X emission 
controls" after each occurrence of "desulfurization 
system";
    e. Removing and reserving paragraph (h);
    f. In paragraph (i)(1), by removing the word "or"; and
    g. Adding paragraph (j).
    The revisions and additions read as follows:

Sec. 75.4  Compliance dates.

* * * * *
    (d) * * *
    (1) The maximum potential concentration of SO₂ (as 
defined in section 2.1.1.1 of appendix A to this part), the maximum 
potential NO_X 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 
CO₂ concentration, as defined in section 2.1.3.1 of appendix 
A to this part;
* * * * *
    (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. If the 
required testing is completed by this deadline, the appendix E 
correlation curve derived from the test results may be used for 
reporting data under this part beginning with the first date and hour 
that the backup fuel is combusted, provided that the fuel flowmeter for 
the backup fuel was certified as of that date and hour. If the required 
appendix E testing has not been successfully completed by the 
compliance date in this paragraph, then, until the testing is 
completed, the owner or operator shall report NO_X emission 
rate data for all unit operating hours that the backup fuel is 
combusted using either:
    (1) The fuel-specific maximum potential NO_X emission 
rate, as defined in Sec. 72.2 of this chapter; or
* * * * *
    (h) [Reserved]
    (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.
    (j) If the certification tests required under paragraph (b) or (c) 
of this section have not been completed by the applicable compliance 
date, the owner or operator shall determine and report SO₂ 
concentration, NO_X emission rate, CO₂ 
concentration, and flow rate data for all unit operating hours after 
the applicable compliance date in this paragraph until all required 
certification tests are successfully completed using either:
    (1) The maximum potential concentration of SO₂, as 
defined in section 2.1.1.1 of appendix A to this part, the maximum 
potential NO_X 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 
CO₂ concentration, as defined in section 2.1.3.1 of appendix 
A to this part;
    (2) Reference methods under Sec. 75.22(b); or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.

Sec. 75.6  [Amended]

    6. Section 75.6 is amended in paragraphs (a)(17), (a)(18), (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 first occurrence of the word 
"The" in the first sentence to read "To determine 
SO₂ 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_X 
emissions, the"; by adding the word "-diluent" after 
the first occurrence of the word "NO_X" in the 
first sentence; and by revising the words "the automated" 
to read "an automated";
    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 
O₂ concentration monitor in order" to read "that 
uses an O₂ 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)(iii) 
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 
"SO₂ 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_X" in the first sentence to read 
"NO_X concentration monitor, flow monitor, moisture 
monitor, or NO_X-diluent", by revising the words 
"An hourly average NO_X or SO₂" in the 
second sentence to read "For a NO_X-diluent monitoring 
system, an hourly average NO_X", by adding the word 
"NO_X" before the word "pollutant" 
and by removing the words "(NO_X or 
SO₂)" in the second sentence, and by revising in the 
fourth sentence the words "Except for SO₂ 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 heading 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.
* * * * *

[[Page 40423]]

Sec. 75.11  [Amended]

    8. Section 75.11 is amended by:
    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 by 
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 colon, 
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_X 
continuous emission monitoring system" to read " 
NO_X-diluent CEMS" in the second sentence;
    c. In paragraph (d)(2) by adding the word "-diluent" 
after NO_X 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_X 
emission rate (NO_X-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_X 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.
* * * * *

Sec. 75.13  [Amended]

    10. Section 75.13 is amended by:
    a. In paragraph (b), by revising in the heading the words 
"Appendix G of" to read "appendix G to", and by 
revising in the first sentence the words "may provide information 
satisfactory to the Administrator" to read "shall follow 
the procedures in appendix G to this part"; and
    b. In paragraph (c) by revising in the first sentence the word 
"may" to read "shall" and the words "dry 
basis" to read "dry basis (or where Equation F-14b in 
appendix F to this part is used to determine CO₂ 
concentration), either", and by revising the comma after the 
reference to "Sec. 75.11(b)(1)" to a semicolon.

Sec. 75.15  [Reserved]

    11. Section 75.15 is removed and reserved.

    12. Section 75.16 is amended by:
    a. Removing the hyphen from the word "by-pass" in the 
section heading;
    b. Removing and reserving paragraph (a);
    c. Revising paragraph (b) heading and introductory text;
    d. Revising paragraph (c);
    e. Amending paragraphs (e) heading, (e) introductory text, (e)(2), 
(e)(3), and (e)(4) by adding the word "rate" after each 
occurrence of the words "heat input";
    f. In paragraph (e)(1) by revising in the first sentence the words 
"choose to install" to read "use the flow rate and 
diluent", by removing in the first sentence the words 
"wherever flow and diluent monitor measurements are used to 
determine the heat input,", by revising the words "(a) 
through (d)" to read "(b) through (d)" in the first 
sentence, by revising the words "(a)(1)(ii), (a)(2)(ii), 
(b)(1)(ii)," to read "(b)(1)(ii)", and by adding at 
the end of the paragraph the words ", according to paragraph 
(e)(3) of this section";
    g. In paragraph (e)(2) by revising the words "appendix F 
of" to read "appendix F to"; and
    h. In paragraph (e)(3) by adding in the second sentence the words 
", in conjunction with the appropriate unit and stack operating 
times" after the words "total steam flow for all units 
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 SO₂ emissions and 
heat input determinations.

    (a) [Reserved]
    (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 SO₂ continuous emission monitoring 
system and flow monitoring system, the owner or operator shall either:
    (1) Install, certify, operate, and maintain separate SO₂ 
continuous emission monitoring systems and flow monitoring systems on 
the main stack and the bypass stack and calculate SO₂ mass 
emissions for the unit as the sum of the SO₂ mass emissions 
measured at the two stacks; or
    (2) Monitor SO₂ mass emissions at the main stack using 
SO₂ and flow rate monitoring systems and measure 
SO₂ mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for SO₂ and flow rate and 
calculate SO₂ 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 SO₂ 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 SO₂ as determined under section 2.1.1.1 of 
appendix A to this part (or, if available, the SO₂ 
concentration measured by a certified monitor located at the control 
device inlet may be reported instead), and the hourly volumetric flow 
rate value that would be substituted for the flow monitor installed on 
the main stack or flue under the missing data procedures in subpart D 
of this part if data from the flow monitor installed on the main stack 
or flue were missing for the hour. The maximum potential SO₂ 
concentration may be specific to the type of fuel combusted in the unit 
during the bypass (see Sec. 75.33(b)(5)). The option in this 
paragraph, (c)(3), 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 SO₂ or 
any other parameter that is monitored only at the main stack. Calculate 
SO₂ mass emissions for the unit as the sum of the emissions 
calculated with the substitute values and the emissions recorded by the 
SO₂

[[Page 40424]]

and flow monitoring systems installed on 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_X" to read "NO_X-
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_X 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_X emission rate in a way that is representative of each 
affected unit. * * *
    (1) Install, certify, operate, and maintain a NO_X-
diluent continuous emission monitoring system and a flow monitoring 
system in each stack or duct and determine the NO_X emission 
rate for the unit as the Btu-weighted average of the NO_X 
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_X 
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_X-diluent monitoring systems 
installed on the individual stacks or ducts as the hourly 
NO_X 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_X missing data procedures in Sec. 75.31 or 
75.33 shall be used for each unit operating hour in which a quality-
assured NO_X 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_X continuous 
emission monitoring system in one stack or duct from the affected unit 
and record the monitored value as the NO_X emission rate for 
the unit. The owner or operator shall account for NO_X 
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(d) for units with bypass stacks. Further, this 
option shall not be used unless the monitored NO_X emission 
rate truly represents the NO_X emissions discharged to the 
atmosphere (e.g., the option is disallowed if there are any additional 
NO_X 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_X-
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_X 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_X emission rate (as defined in Sec. 72.2 
of this chapter). The maximum potential NO_X emission rate 
may be specific to the type of fuel combusted in the unit during the 
bypass (see Sec. 75.33(c)(8)).

    14. Section 75.19 is amended by:
    a. Revising the section heading, paragraph (a), and paragraphs 
(b)(1), (b)(2), (b)(3), (b)(4)(i), (b)(5), (c)(1)(i), (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv)(C), (c)(3)(ii)(C), (c)(3)(ii)(D) introductory 
text, (c)(3)(ii)(D)(1), (c)(3)(ii)(E), (c)(3)(ii)(F), (c)(3)(ii)(G), 
(c)(3)(ii)(H), and (e)(2);
    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" and the words "a 
low" to read "the low";
    c. Amending paragraph (b)(4)(ii) by revising the words 
"NO_X, and CO₂" to read 
"CO₂, and/or NO_X";
    d. Amending paragraph (b)(4)(iii) by revising the words "and 
NO_X" in the first sentence to read "and/or 
NO_X", revising the second sentence, and by revising 
the word "The" in the third sentence to read "For 
Acid Rain Program LME units, the";
    e. In paragraph (c)(1)(iv) introductory text by adding a new 
sentence after the second sentence;
    f. By revising in the first sentence of paragraph (c)(1)(iv)(A) the 
words "(c)(1)(iv)(F) and (G) of this paragraph" to read 
"(c)(1)(iv)(F), (c)(1)(iv)(G), and (c)(1)(iv)(I) of this 
section" and by adding new paragraphs (c)(1)(iv)(A)(3) and (4) 
and Equation LM-1a;
    g. Removing and reserving paragraph (c)(1)(iv)(B)(3);
    h. Amending paragraph (c)(1)(iv)(B)(4) by revising the reference to 
"(c)(1)(iv)(B)(3)" to read "(c)(1)(iv)(B)(1)";
    i. In paragraph (c)(1)(iv)(D) by revising in the first sentence the 
words ", each unit in a group of units sharing a common fuel 
supply, or" to read "or group of", by adding in the 
first sentence the words "(20 calendar quarters)" after the 
words "five years", and by adding a new sentence after the 
second sentence;
    j. Amending paragraph (c)(1)(iv)(E) by removing the words ", 
each low mass emission unit in a group of units combusting a common 
fuel,";
    k. Revising the first and last sentences of (c)(1)(iv)(G);
    l. Amending the first sentence of (c)(1)(iv)(H) by revising the 
first occurrence of the words "NO_X emission 
controls," to read "add-on NO_X emission 
controls, and for units that use dry low-NO_X 
technology,";
    m. Amending the last sentence of (c)(1)(iv)(H)(1) by adding the 
words ", and the appropriate default NO_X emission rate 
from Table LM-2 shall be reported instead" after the words 
"that hour";
    n. Redesignating existing paragraph (c)(1)(iv)(H)(2) as 
(c)(1)(iv)(H)(3), and adding the words ", and the appropriate 
default NO_X emission rate from Table LM-2 shall be 
reported instead" after the words "that hour" and 
adding new paragraph (c)(1)(iv)(H)(2);
    o. Adding new paragraphs (c)(1)(iv)(I) and (c)(1)(iv)(J);
    p. In paragraph (c)(2) introductory text by adding the words 
", except that for unmanned facilities, the records may be kept 
at a central location, rather than on-site" after the word 
"inspection";
    q. In paragraph (c)(2)(iii) by revising the word 
"output" to read "load" and by adding the words 
"per hour" after the words "pounds of steam";
    r. In paragraph (c)(2)(iv) by adding the words "add-on" 
after the words "unit with" and adding the words "and 
each unit that uses dry low-NO_X technology" after the 
words "of any kind";

[[Page 40425]]

    s. In paragraph (c)(3)(i)(A) by adding 
"HI_hr," after the words "of this 
section," in the first sentence, by revising Eq. LM-1 in 
paragraph (c)(3)(i)(B) and the accompanying variable definitions, and 
by adding a new paragraph (c)(3)(i)(D);
    t. In paragraphs (c)(3)(ii)(I) and (c)(3)(ii)(J) by revising the 
definition of variables following Equations LM-7, LM-8, 
LM-7a, and LM-8a;
    u. In paragraph (c)(4)(i)(A) by adding the words "(Acid Rain 
Program units, only)" after the word "unit" in the 
first sentence, by capitalizing the first letter of the word 
"where", and by revising the definition of variable 
"EF_SO₂" for Equation LM-9;
    v. In paragraph (c)(4)(ii)(A) by correcting the variables 
"WNO_X" and "EFNO_X" to 
read "W_NO_X" and 
"EF_NO_X";
    w. In paragraph (c)(4)(ii)(C) by adding a new sentence to the end 
of this paragraph;
    x. In paragraph (c)(4)(iii)(A) by adding the words "(Acid 
Rain Program units, only)" after the word "unit" in 
the first sentence and by revising the definition of the variable 
"EFCO2" under Equation LM-11;
    y. Amending paragraph (e)(5) by revising the words "which 
have NO_X emission controls of any kind" to read 
"which has add-on NO_X emission controls of any kind or 
uses dry low-NO_X technology";
    z. Adding new paragraph (e)(6) between paragraph (e)(5) and table 
LM-1;
    aa. Amending Table LM-2 that follows paragraph (e) by 
revising the words "Boiler type" to read "Unit 
type" in heading for the first column;
    bb. Amending Table LM-3 that follows paragraph (e) by 
revising the words "Natural Gas" to read "Pipeline 
(or other) Natural Gas" in the first column; and
    cc. Amending Table LM-5 that follows paragraph (e) by adding 
the word "Other" before "Natural Gas" in the 
first column of the table.
    The revisions and additions read as follows:

Sec. 75.19  Optional SO₂, NO_X, and 
CO₂ emissions calculation for low mass emissions (LME) 
units.

    (a) Applicability and qualification. (1) For units that meet the 
requirements of this paragraph (a)(1) and paragraphs (a)(2) and (b) of 
this section, the low mass emissions excepted methodology in paragraph 
(c) of this section may be used in lieu of continuous emission 
monitoring systems or, if applicable, in lieu of excepted methods under 
appendix D or E to this part, for the purpose of determining hourly 
heat input and hourly NO_X, SO₂, and 
CO₂ mass emissions under this part.
    (i) A low mass emissions unit is an affected unit that is gas-
fired, or oil-fired (as defined in Sec. 72.2 of this chapter), 
and for which:
    (A) An initial demonstration is provided, in accordance with 
paragraph (a)(2) of this section, which shows that the unit emits:
    (1) No more than 25 tons of SO₂ annually and less than 
100 tons of NO_X annually, for Acid Rain Program affected 
units. If the unit is also subject to the provisions of subpart H of 
this part, no more than 50 of the allowable annual tons of 
NO_X may be emitted during the ozone season; or
    (2) Less than 100 tons of NO_X annually and no more than 
50 tons of NO_X during the ozone season, for non-Acid Rain 
Program units subject to the provisions of subpart H of this part, for 
which the owner or operator reports emissions data on a year-round 
basis, in accordance with Sec. 75.74(a) or 
Sec. 75.74(b); or
    (3) No more than 50 tons of NO_X per ozone season, for 
non-Acid Rain Program units subject to the provisions of subpart H of 
this part, for which the owner or operator reports 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 emissions unit continues to emit no more than the 
applicable number of tons of SO₂ and/or NO_X 
specified in paragraph (a)(1)(i)(A) of this section.
    (C) This paragraph, (a)(1)(i)(C), applies only to a unit that is 
subject to an SO₂ emission limitation under the Acid Rain 
Program, and that combusts a gaseous fuel other than pipeline natural 
gas or natural gas (as defined in Sec. 72.2 of this chapter). 
The owner or operator of such a unit must quantify the sulfur content 
and variability of the gaseous fuel by performing the demonstration 
described in section 2.3.6 of appendix D to this part, in order for the 
unit to qualify for LME unit status. If the results of that 
demonstration show that the gaseous fuel qualifies under paragraph (b) 
of section 2.3.6 to use a default SO₂ emission rate to 
report SO₂ mass emissions under this part, the unit is 
eligible for LME unit status.
    (ii) Each qualifying LME 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 designated in the certification application as the first 
year that the methodology will be used; 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 designated in the certification 
application as the first ozone season that the methodology will be 
used.
    (C) For a new or newly-affected unit, see paragraph (b)(4) of this 
section for additional guidance.
    (2) A unit may initially qualify as a low mass emissions unit if 
the designated representative submits a certification application to 
use the LME methodology (as described in Sec. 75.63(a)(1)(ii) 
and in this paragraph, (a)(2)) and the Administrator (or permitting 
authority, as applicable) 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 methodology is 
expected to commence, and the application must contain:
    (i) A statement identifying the projected date on which the LME 
methodology will first be used. The projected commencement date shall 
be consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as 
applicable; and
    (ii) Either:
    (A) Actual SO₂ and/or NO_X mass emissions data 
(as applicable) for each of the three calendar years (or ozone seasons) 
prior to the calendar year in which the certification application is 
submitted demonstrating to the satisfaction of the Administrator or (if 
applicable) the permitting authority, that the unit emitted less than 
the applicable number of tons of SO₂ and/or NO_X 
specified in paragraph (a)(1)(i)(A) of this section. For the purposes 
of this paragraph, (a)(2)(ii)(A), the required actual SO₂ or 
NO_X mass emissions for each qualifying year or ozone season 
shall be determined using the SO₂, NO_X and heat 
input data reported to the Administrator in the electronic quarterly 
reports required under Sec. 75.64 or under the Ozone Transport 
Commission (OTC) NO_X Budget Trading Program. Notwithstanding 
this requirement, in the absence of such electronic reports, an 
estimate of the actual emissions for each of the previous three years 
(or ozone seasons) shall be provided, using either the maximum rated 
heat input methodology described in paragraph (c)(3)(i) of this section 
or procedures consistent with the long term fuel flow heat input 
methodology described in paragraph (c)(3)(ii) of this section, in 
conjunction with the appropriate SO₂ or NO_X 
emission rate from paragraph

[[Page 40426]]

(c)(1)(i) of this section for SO₂, and paragraph (c)(1)(ii) 
or (c)(1)(iv) of this section for NO_X. Alternatively, the 
initial estimate of the NO_X emission rate may be based on 
historical emission test data that is representative of operation at 
normal load or historical data from a CEMS certified under part 60 of 
this chapter or under a state CEM program; or
    (B) When the three full years (or ozone seasons) of actual SO₂ 
and NO_X mass emissions data (or reliable estimates thereof) 
described under paragraph (a)(2)(ii)(A) of this section do not exist, 
the designated representative may submit an application to use the low 
mass emissions excepted methodology based upon a combination of actual 
historical SO₂ and NO_X mass emissions data and 
projected SO₂ and NO_X mass emissions, totaling 
three years (or ozone seasons). Except as provided in paragraph (a)(3) 
of this section, actual data must be used for any years (or ozone 
seasons) in which such data exists and projected data should be used 
for any remaining future years (or ozone seasons) needed to provide 
emissions data for three consecutive calender years (or ozone seasons). 
For example, if a 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 unit, the designated representative may 
submit three years of projected emissions, beginning with the current 
calendar year. Any actual or projected annual emissions must 
demonstrate to the satisfaction of the Administrator that the unit will 
emit less than the applicable number of tons of SO₂ and/or 
NO_X specified in paragraph (a)(1)(i)(A) of this section. 
Projected emissions shall be calculated using either the appropriate 
default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this 
section (or, alternatively for NO_X, a conservative estimate 
of the NO_X emission rate, as described in paragraph (a)(4) 
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; and
    (iii) A description of the methodology from paragraph (c) of this 
section that will be used to demonstrate on-going compliance under 
paragraph (b) of this section; and
    (iv) Appropriate documentation demonstrating that the unit is 
eligible to use projected emissions to qualify for LME status under 
paragraph (a)(3) of this section (if applicable).
    (3) In the following circumstances, projected emissions for a 
future year (or years) may be used in lieu of the actual emissions data 
from one (or more) of the three years (or ozone seasons) preceding the 
year of the certification application:
    (i) If the owner or operator takes an enforceable permit 
restriction on the number of annual or ozone season unit operating 
hours for the future year (or years), such that the unit will emit no 
more than the applicable number of tons of SO₂ and/or 
NO_X specified in paragraph (a)(1)(i)(A) of this section; or
    (ii) If the actual emissions for one (or more) of the three years 
(or ozone seasons) prior to the year of the certification application 
is not representative of the present and expected future emissions from 
the unit, because the owner or operator has recently installed emission 
controls on the unit.
    (4) When the owner or operator elects to demonstrate initial LME 
qualification and on-going compliance using a fuel-and-unit-specific 
NO_X emission rate in accordance with paragraph (c)(1)(iv) of 
this section, there will be instances (e.g., for a new or newly-
affected unit) where it is not possible to determine that 
NO_X emission rate prior to submitting the certification 
application. In such cases, if the generic default NO_X 
emission rates in Table LM-2 of this section are inappropriately 
high for the unit, the owner or operator may use a more representative, 
but conservatively high estimate of the expected NO_X 
emission rate, for the purposes of the initial monitoring plan 
submittal and to calculate the unit's projected annual or ozone season 
emissions under paragraph (a)(2)(ii)(B) of this section. For example, 
the NO_X emission rate could, as described in paragraph 
(a)(2)(ii)(A) of this section, be estimated using historical CEM data 
or historical emission test data that is representative of operation at 
normal load. The NO_X emission limit specified in the 
operating permit for the unit could also be used to estimate the 
NO_X emission rate (except for units equipped with SCR or 
SNCR), or, consistent with paragraph (c)(1)(iv)(C)(4) of this section, 
for a unit that uses SCR or SNCR to control NO_X emissions, 
an estimated default NO_X emission rate of 0.15 lb/mmBtu 
could be used. However, these estimated NO_X emission rates 
may not be used for reporting purposes in the time period extending 
from the first hour in which the LME methodology is used to the date 
and hour on which the fuel-and-unit-specific NO_X emission 
rate testing is completed. Rather, in that interval, the owner or 
operator shall either report the appropriate default NO_X 
emission rate from Table LM-2, or shall report the maximum 
potential NO_X emission rate, calculated in accordance with 
Sec. 72.2 of this chapter and section 2.1.2.1 of appendix A to 
this part. Then, beginning with the first unit operating hour after 
completion of the tests, the appropriate default NO_X 
emission rate(s) obtained from the fuel-and-unit-specific testing shall 
be used for emissions reporting.
    (b) On-going qualification and disqualification. (1) Once a low 
mass emissions 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 SO₂ and/or NO_X 
specified in paragraph (a)(1)(i)(A) of this section. The calculation 
methodology used for the annual demonstration shall be the methodology 
described in the certification application under paragraph (a)(2)(iii) 
of this section.
    (2) If any low mass emissions 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 SO₂ and/or NO_X 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 emissions unit shall be disqualified from using 
the low mass emissions excepted methodology; and
    (ii) The owner or operator of the low mass emissions unit shall 
install and certify monitoring systems that meet the requirements of 
Sec. 75.11, 75.12, and 75.13, and shall report SO₂ 
(Acid Rain Program units, only), NO_X, and CO₂ 
(Acid Rain Program units, only) emissions data and heat input data from 
such monitoring systems by December 31 of the calendar year following 
the year in which the unit exceeded the number of tons of SO₂ 
and/or NO_X specified in paragraph (a)(1)(i)(A) of this 
section; and
    (iii) If the required monitoring systems have not been installed 
and certified by the applicable deadline in paragraph (b)(2)(ii) of 
this section, 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 potential hourly heat input 
for the unit, as defined in Sec. 72.2 of this chapter; the 
SO₂ emissions, in lb/hr, calculated using the applicable 
default SO₂ emission rate from paragraph (c)(1)(i) of this 
section and the maximum potential hourly unit heat input; the 
CO₂

[[Page 40427]]

emissions, in tons/hr, calculated using the applicable default 
CO₂ emission rate from paragraph (c)(1)(iii) of this section 
and the maximum potential hourly unit heat input; and the maximum 
potential NO_X emission rate, as defined in Sec. 72.2 
of this chapter.
    (3) If a low mass emissions 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 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 and certify SO₂ (Acid Rain Program 
units, only), NO_X, and CO₂ (Acid Rain Program 
units, only) and flow (if necessary) monitoring systems that meet the 
requirements of Sec. 75.11, 75.12, and 75.13 prior to a 
change to such fuel, and shall report emissions data from such 
monitoring systems beginning with the date and hour on which the new 
fuel is first combusted in the unit. 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 SO₂, CO₂ and NO_X, the 
maximum potential NO_X 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 SO₂, NO_X and CO₂ 
monitoring system meeting the requirements of Sec. 75.11, 
75.12, and 75.13.
    (4) * * *
    (i) Keep the records specified in paragraph (c)(2) of this section, 
beginning with the date and hour of commencement of commercial 
operation, for a new unit subject to an Acid Rain emission limitation, 
and beginning with the date and hour of the commencement of operation, 
for a new unit subject to a NO_X mass reduction program under 
subpart H of this part. For newly-affected units, the records in 
paragraph (c)(2) of this section shall be kept as follows:
    (A) For Acid Rain Program units, begin keeping the records as of 
the first hour of commercial operation of the unit following the date 
on which the unit becomes affected; or
    (B) For units subject to a NO_X mass reduction program 
under subpart H of this part, begin keeping the records as of the first 
hour of unit operation following the date on which the unit becomes an 
affected unit;
* * * * *
    (iii)* * * For example, use the default emission rates in 
table LM-1, LM-2, and LM-3 of this section or use the 
fuel-and-unit-specific NO_X emission rate determined 
according to paragraph (c)(1)(iv) of this section. * * *
    (5) A low mass emissions unit that has been disqualified from using 
the low mass emissions excepted methodology may subsequently submit an 
application to qualify again to use the low mass emissions methodology 
under paragraph (a)(2) of this section only if, following the non-
compliant year (or ozone season), at least three full years (or ozone 
seasons) of actual, monitored emissions data is obtained showing that 
the unit emitted no more than the applicable number of tons of SO₂ 
and/or NO_X specified in paragraph (a)(1)(i)(A) of this 
section. Further, the designated representative or authorized account 
representative must certify in the application that the unit operation 
for the years or ozone seasons for which the emissions were monitored 
are representative of the projected future operation of the unit.
    (c) Low mass emissions excepted methodology, calculations, and 
values. (1) Determination of SO₂, NO_X, and 
CO₂ emission rates.
    (i) If the unit combusts only natural gas and/or fuel oil, use 
Table LM-1 of this section to determine the appropriate 
SO₂ emission rate for use in calculating hourly 
SO₂ mass emissions under this section (Acid Rain Program 
units, only). If the unit combusts gaseous fuel(s) other than natural 
gas, the owner or operator shall use the procedures in section 2.3.6 of 
appendix D to this part to document the total sulfur content of each 
such fuel and to determine the appropriate default SO₂ 
emission rate for each such fuel.
    (ii) If the unit combusts only natural gas and/or fuel oil, use 
either the appropriate NO_X emission factor from Table 
LM-2 of this section, or a fuel-and-unit-specific NO_X 
emission rate determined according to paragraph (c)(1)(iv) of this 
section, to calculate hourly NO_X mass emissions under this 
section. If the unit combusts a gaseous fuel other than pipeline 
natural gas or natural gas, the owner or operator shall determine a 
fuel-and-unit-specific NO_X emission rate according to 
paragraph (c)(1)(iv) of this section.
    (iii) If the unit combusts only natural gas and/or fuel oil, use 
Table LM-3 of this section to determine the appropriate 
CO₂ emission rate for use in calculating hourly 
CO₂ mass emissions under this section (Acid Rain Program 
units, only). If the unit combusts a gaseous fuel other than pipeline 
natural gas or natural gas, the owner or operator shall determine a 
fuel-and-unit-specific CO₂ emission rate for the fuel, as 
follows:
    (A) Derive a carbon-based F-factor for the fuel, using fuel 
sampling and analysis, as described in section 3.3.6 of appendix F to 
this part; and
    (B) Use Equation G-4 in appendix G to this part to derive the 
default CO₂ emission rate. Rearrange the equation, solving 
it for the ratio of W_CO2/H (this ratio will yield an 
emission rate, in units of tons/mmBtu). Then, substitute the carbon-
based F-factor determined in paragraph (c)(1)(iii)(A) of this section 
into the rearranged equation to determine the default CO₂ 
emission rate for the unit.
    (iv) * * * The testing must be completed in a timely 
manner, such that the test results are reported electronically no later 
than the end of the calendar year or ozone season in which the LME 
methodology is first used. * * *
    (A) * * *
    (3) When using Method 20 for turbines do not correct the 
NO_X concentration to 15% O₂.
    (4) If the testing is performed on an uncontrolled diffusion flame 
turbine, a correction to the observed average NO_X 
concentration from each run of the Method 20 test must be applied using 
the following Equation LM-1a.

[[Page 40428]]

[GRAPHIC]
[TIFF OMITTED]
TR12JN02.000

Where:

NO_Xcorr = Corrected NO_X concentration (ppm).
NO_Xobs = Average measured NO_X concentration for 
each run of the Method 20 test (ppm).
P_r = 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 (mm Hg).
P_o = Observed atmospheric pressure during the test run (mm 
Hg).
H_r = 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 (g H₂O/g 
air).
H_o = Observed humidity ratio during the test run (g 
H₂O/g air).
T_r = 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. K).
T_a = Observed atmospheric temperature during the test run 
(deg. K).

    (B) * * *
    (3) [Reserved]
* * * * *
    (C) Based on the results of the part 75 appendix E testing, 
determine the fuel-and-unit-specific NO_X emission rate as 
follows:
    (1) Except for LME units that use selective catalytic reduction 
(SCR) or selective non-catalytic reduction (SNCR) to control 
NO_X emissions, the highest three-run average NO_X 
emission rate obtained at any load in the appendix E test for a 
particular type of fuel shall be the fuel-and-unit-specific 
NO_X emission rate, for that type of fuel.
    (2) [Reserved]
    (3) For a group of identical low mass emissions units (except for 
units that use SCR or SNCR to control NO_X emissions), the 
fuel-and-unit-specific NO_X emission rate for all units in 
the group, for a particular type of fuel, shall be the highest three-
run average NO_X emission rate obtained at any tested load 
from any unit tested in the group, for that type of fuel.
    (4) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for an individual low mass emissions 
unit which uses SCR or SNCR to control NO_X emissions, the 
fuel-and-unit-specific NO_X emission rate for each type of 
fuel combusted in the unit shall be the higher of:
    (i) The highest three-run average emission rate from any load of 
the appendix E test for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (5) [Reserved]
    (6) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for a group of identical low mass 
emissions units that are all equipped with SCR or SNCR to control 
NO_X emissions, the fuel-and-unit-specific NO_X 
emission rate for each unit in the group of units, for a particular 
type of fuel, shall be the higher of:
    (i) The highest three-run average NO_X emission rate at 
any load from all appendix E tests of all tested units in the group, 
for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (7) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and water (or steam) injection to 
control NO_X emissions:
    (i) If the appendix E testing is performed when the water (or steam 
) injection is in use and either upstream of the SCR or SNCR or during 
a time period when the SCR or SNCR is out of service; then
    (ii) The highest three-run average emission rate from the appendix 
E testing may be used as the fuel-and-unit-specific NO_X 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the water-to-fuel ratio 
is within the acceptable range established during the appendix E 
testing.
    (8) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and uses dry low-NO_X 
technology to control NO_X emissions:
    (i) If the appendix E testing is performed during a time period 
when the dry low-NO_X controls are in use, but the SCR or 
SNCR is out of service; then
    (ii) The highest three-run average emission rate from the appendix 
E testing may be used as the fuel-and-unit-specific NO_X 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the parametric data 
described in paragraph (c)(1)(iv)(H)(2) of this section demonstrate 
that the dry low-NO_X controls are operating in the premixed 
or low-NO_X mode.
    (9) For an individual combustion turbine (or a group of identical 
turbines) that operate principally at base load (or at a set point 
temperature), but are capable of operating at a higher peak load (or 
higher internal operating temperature), the fuel-and-unit-specific 
NO_X emission rate for the unit (or for each unit in the 
group) shall be as follows:
    (i) If the testing is done only at base load, use the three-run 
average NO_X emission rate for base load operating hours and 
1.15 times that emission rate for peak load operating hours; or
    (ii) If the testing is done at both base load and peak load, use 
the three-run average NO_X emission rate from the base load 
testing for base load operating hours and the three-run average 
NO_X emission rate from the peak load testing for peak load 
operating hours.
    (D) * * * Testing shall be done at the number of loads 
specified in paragraph (c)(1)(iv)(A) or (c)(1)(iv)(I) of this section, 
as applicable. * * *
* * * * *
    (G) Low mass emissions units for which at least 3 years of quality-
assured NO_X emission rate data from a NO_X-diluent 
CEMS and corresponding fuel usage data are available may determine 
fuel-and-unit-specific NO_X 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_X emission rate, except that for a unit that uses SCR or 
SNCR for NO_X emission control, 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_X emission rate.
    (H) * * *
    (2) For a low mass emissions unit that uses dry low-NO_X 
premix technology to control NO_X emissions, proper operation 
of the emission controls means that the unit is in the low-
NO_X or premixed combustion mode, and fired with natural gas. 
Evidence of operation in the low-NO_X or premixed mode shall 
be provided by monitoring the appropriate turbine operating

[[Page 40429]]

parameters. These parameters may include percentage of full load, 
turbine exhaust temperature, combustion reference temperature, 
compressor discharge pressure, fuel and air valve positions, dynamic 
pressure pulsations, internal guide vane (IGV) position, and flame 
detection or flame scanner condition. The acceptable values and ranges 
for all parameters monitored shall be specified in the monitoring plan 
for the unit, and the parameters shall be monitored during each 
subsequent operating hour. If one or more of these parameters is not 
within the acceptable range or at an acceptable value in a given 
operating hour, the fuel-and-unit-specific NO_X emission rate 
may not be used for that hour, and the appropriate default 
NO_X emission rate from Table LM-2 shall be reported 
instead. When the unit is fired with oil the appropriate default value 
from Table LM-2 shall be reported.
* * * * *
    (I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of 
this section, the appendix E testing to determine (or re-determine) the 
fuel-specific, unit-specific NO_X emission rate for a unit 
(or for each unit in a group of identical units) may be performed at 
fewer than four loads, under the following circumstances:
    (1) Testing may be done at one load level if the data analysis 
described in paragraph (c)(1)(iv)(J) of this section is performed and 
the results show that the unit has operated (or 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 
testing. 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 the 
operation of the turbine, the internal operating temperature set point 
may be used as a surrogate for load in demonstrating that the unit 
qualifies for single-load testing. If the data analysis shows that the 
unit does not qualify for single-load testing, testing may be done at 
two (or three) load levels if the unit has operated (or if all units in 
the group of identical units have operated) cumulatively at two (or 
three) load levels for at least 85.0 percent of all operating hours in 
the previous three years; or
    (2) If a multiple-load appendix E test was initially performed for 
a unit (or group of identical units) to determine the fuel-and-unit 
specific NO_X emission rate, then the periodic retests 
required under paragraph (c)(1)(iv)(D) of this section may be single-
load tests, performed at the load level for which the highest average 
NO_X emission rate was obtained in the initial test.
    (J) To determine whether a unit qualifies for testing at fewer than 
four loads under paragraph (c)(1)(iv)(I) of this section, follow the 
procedures in paragraph (c)(1)(iv)(J)(1) or (c)(1)(iv)(J)(2) of this 
section, as applicable.
    (1) 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: from 20 MW to 40 MW; band #2: from 41 MW to 60 MW; 
band #3: from 61 MW to 80 MW; and band #4: from 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. 
Alternatively, for sources that report emissions data only during the 
ozone season, the historical load analysis may be based on unit 
operation in the previous three ozone seasons, rather than unit 
operation in the previous 12 calendar quarters. Determine the 
percentage of the data that fall into each load band. For a unit that 
is not part of a group of identical units, if 85.0% or more of the data 
fall into one load band, 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% criterion, then representative 
single-load testing within the load band may be performed. If the 85.0% 
criterion cannot be met to qualify for single-load testing but this 
criterion can be met cumulatively for two (or three) load levels, then 
testing may be performed at two (or three) loads instead of four.
    (2) For a combustion turbine that uses exhaust temperature and not 
the actual output in megawatts to control the operation of the turbine 
(or for a group of identical units of this type), the owner or operator 
must document that the unit (or each unit in the group) has operated 
within &plusmn; 10% of the set point temperature for 85.0% of the 
operating hours in the previous 12 calendar quarters to qualify for 
single-load testing. Alternatively, for sources that report emissions 
data only during the ozone season, the historical set point temperature 
analysis may be based on unit operation in the previous three ozone 
seasons, rather than unit operation in the previous 12 calendar 
quarters. When the set point temperature is used rather than unit load 
to justify single-load testing, the designated representative shall 
certify in the monitoring plan for the unit that this is the normal 
manner of unit operation and shall document the setpoint temperature.
* * * * *
    (3) Heat input. * * *
    (i) Maximum rated hourly heat input method. * * *
    (B) * * *
    [GRAPHIC]
[TIFF OMITTED]
TR12JN02.001
    
Where:

n = Number of unit operating hours in the quarter.
HI_hr = 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, for compliance 
purposes, 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 heat 
input values for May, June and the third calendar quarter of the year.
    (ii) Long term fuel flow heat input method. * * *
    (C) Except as provided in paragraph (c)(3)(ii)(C)(3) of this 
section, for each fuel combusted during a quarter, the gross calorific 
value of the fuel shall be determined by either:
    (1) Using the applicable procedures for gas and oil analysis in 
sections 2.2 and 2.3 of appendix D to this part. If this option is 
chosen the highest gross calorific value recorded during the previous 
calendar year shall be used (or, for a new or newly-affected unit, if 
there are no sample results from the previous year, use the highest GCV 
from the samples taken in the current year); or
    (2) Using the appropriate default gross calorific value listed in 
Table LM-5 of this section.
    (3) For gaseous fuels other than pipeline natural gas or natural 
gas, the GCV sampling frequency shall be daily unless the results of a 
demonstration under section 2.3.5 of appendix D to this part show that 
the fuel has a low GCV variability and qualifies for monthly sampling. 
If daily GCV sampling is required, use the highest GCV obtained in the 
calendar quarter as GCV_max in Equation LM-3, of this 
section.

[[Page 40430]]

    (D) If Eq. LM-2 is used for heat input determination, the 
specific gravity of each type of fuel oil combusted during the quarter 
shall be determined either by:
    (1) Using the procedures in section 2.2.6 of appendix D to this 
part. If this option is chosen, use the highest specific gravity value 
recorded during the previous calendar year (or, for a new or newly-
affected unit, if there are no sample results from the previous year, 
use the highest specific gravity from the samples taken in the current 
year); or
* * * * *
    (E) The quarterly heat input from each type of fuel combusted 
during the quarter by a low mass emissions unit or group of low mass 
emissions units sharing a common fuel supply shall be determined using 
either Equation LM-2 or Equation LM-3 for oil (as 
applicable to the method used to quantify oil usage) and Equation 
LM-3 for gaseous fuels. 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.
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.002

Where:

HI_fuel-qtr = Quarterly total heat input from oil (mmBtu).
M_qtr = Mass of oil consumed during the quarter, determined 
as the product of the volume of oil under paragraph (c)(3)(ii)(B) of 
this section and the specific gravity under paragraph (c)(3)(ii)(D) of 
this section (lb).
GCV_max = Gross calorific value of oil, as determined under 
paragraph (c)(3)(ii)(C) of this section (Btu/lb)
10\6\ = Conversion of Btu to mmBtu.
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.003

Where:

HI_fuel-qtr = Quarterly heat input from gaseous fuel or fuel 
oil (mmBtu).
Q_qtr = Volume of gaseous fuel or fuel oil combusted during 
the quarter, as determined under paragraph (c)(3)(ii)(B) of this 
section standard cubic feet (scf) or (gal), as applicable.
GCV_max = Gross calorific value of the gaseous fuel or fuel 
oil combusted during the quarter, as determined under paragraph 
(c)(3)(ii)(C) of this section (Btu/scf) or (Btu/gal), as applicable.
10\6\ = Conversion of Btu to mmBtu.
    (F) Use Eq. LM-4 to calculate HI_qtr-total, the 
quarterly heat input (mmBtu) for all fuels. HI_qtr-total, 
shall be the sum of the HI_fuel-qtr values determined using 
Equations LM-2 and LM-3.
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.004

    (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 emissions unit or each low mass emissions 
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 Equations 
LM-5 or LM-6. For a unit subject to the provisions of 
subpart H of this part, which is not required to report emission data 
on a year-round basis and elects to report only during the ozone 
season, the quarterly cumulative load for the second calendar quarter 
of the year shall include only the unit loads for the months of May and 
June.
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.005

[GRAPHIC]
[TIFF OMITTED]
TR12JN02.006

Where:

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

    (I) * * *

Where:

HI_hr = Hourly heat input to the unit (mmBtu).
MW_hr = Hourly operating load for the unit (MW).
ST_hr = Hourly steam load for the unit (klb of steam/hr).

    (J) * * *

Where:

HI_hr = Hourly heat input to the individual unit (mmBtu).
MW_hr = Hourly operating load for the individual unit (MW).
ST_hr = Hourly steam load for the individual unit (klb of 
steam/hr).

[[Page 40431]]

MWqtr = Sum 
of the quarterly operating
    all-units loads (from Eq. LM-5) for all units in the group 
(MW).
STqtr = Sum 
of the quarterly steam
    all-units loads (from Eq. LM-6) for all units in the group 
(klb of steam/hr)

    (4) Calculation of SO₂, NO_X and CO₂ 
mass emissions. * * *
    (i) SO₂ mass emissions.
    (A) * * *

Where: * * *

EF_SO2 = Either the SO₂ emission factor from Table 
LM-1 of this section or the fuel-and-unit-specific SO₂ 
emission rate from paragraph (c)(1)(i) of this section (lb/mmBtu).
* * * * *
    (ii) NO_X mass emissions.
* * * * *
    (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_X mass emissions for the unit shall be the 
sum of the quarterly NO_X mass emissions, as determined under 
paragraph (c)(4)(ii)(B) of this section, for the second and third 
calendar quarters of the year, and the second quarter report shall 
include emissions data only for May and June.
    (iii) CO₂ Mass Emissions.
    (A) * * *

Where: * * *

EF_CO2 = Either the fuel-based CO₂ emission factor 
from Table LM-3 of this section or the fuel-and-unit-specific 
CO₂ emission rate from paragraph (c)(1)(iii) of this section 
(tons /mmBtu). * * *
* * * * *
    (e) * * *
    (2) For low mass emissions units or groups of units which use the 
long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section and which use one of the methods specified in paragraph 
(c)(3)(ii)(B)(2) of this section to determine fuel usage, the owner or 
operator shall keep, at the facility, a copy of the standard used and 
shall keep records, for three years, of all measurements obtained for 
each quarter using the methodology.
* * * * *
    (6) For unmanned facilities, the records required by paragraphs 
(e)(1), (e)(2) and (e)(4) of this section may be kept at a central 
location, rather than at the facility.
* * * * *

    15. Section 75.20 is amended by:
    a. Revising paragraphs (b)(3)(i), (c)(2)(ii), (c)(2)(iii), (c)(4) 
introductory text, (c)(4)(i) through (iii), (g)(2), (h)(1), (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 CO₂ continuous emission 
monitoring system,";
    c. In paragraph (a)(3) by revising in the first sentence the words 
"section for each continuous emission or opacity monitoring 
system or component thereof," to read "section, 
each", by removing the words "or component thereof" 
in each of the two remaining occurrences of these words, and by 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 paragraph (b)(2) by removing the word "not" 
before the words "required for certification";
    h. In paragraph (b)(5) by revising the third and fourth sentences;
    i. In paragraph (c) introductory text by adding in the third 
sentence the word "otherwise" before the word 
"specified," and the words "and in sections 6.3.1 and 
6.3.2 of appendix A to this part," after the words "(b)(1), 
(d), & (e) of this section,";
    j. Removing the second paragraph designated (c)(1)(v) and paragraph 
(h)(4)(iii);
    k. Adding new paragraphs (c)(2)(iv) and (h)(5);
    l. In paragraph (d)(2)(iii) by removing the words "or 
SO₂-diluent" in the third sentence, by revising the 
last sentence, and by adding two new sentences at the end of the 
paragraph;
    m. 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;
    n. In the third sentence of (d)(2)(vii) by revising the words 
"analyzer and specify" to read "analyzer, beginning 
with the letters "LK" (e.g., "LK1," 
"LK2," etc.) and shall specify";
    o. Adding a sentence to the end of paragraph (g)(1)(i);
    p. In paragraph (g)(5) by adding the words "(or 
recertified)" after both occurrences of the words 
"provisionally certified", by 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, and by removing the word 
"either" from the second sentence; and
    q. In paragraph (h)(2) by revising the reference to 
"Sec. 75.63(a)(1)(iii)" to read 
"Sec. 75.63(a)(1)(ii)".
    The revisions and additions read as follows:

Sec. 75.20  Initial certification and recertification 
procedures.

* * * * *
    (b) * * *
    (3) * * *
    (i) The owner or operator shall use substitute data, according to 
the standard missing data procedures in Sec. 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 either: the 
hour of successful completion of all of the required recertification 
tests; or the hour in which a probationary calibration error test 
(according to paragraph (b)(3)(ii) of this section) is performed and 
passed, following all necessary repairs, adjustments or reprogramming 
of the monitoring system. 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. Notwithstanding these requirements, 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 SO₂ concentration and stack flow rate change 
significantly after

[[Page 40432]]

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 Sec. 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.
* * * * *
    (5) * * * In the event that a recertification application is 
disapproved, data from the monitoring system are invalidated and the 
applicable missing data procedures in Sec. 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) Initial certification and recertification procedures.
* * * * *
    (2) * * *
    (ii) Relative accuracy test audits, as follows:
    (A) A single-load (or single-level) RATA at the normal load (or 
level), as defined in section 6.5.2.1(d) of appendix A to this part, 
for a flow monitor installed on a peaking unit or bypass stack, or for 
a flow monitor exempted from multiple-level RATA testing under section 
6.5.2(e) of appendix A to this part;
    (B) For all other flow monitors, a RATA at each of the three load 
levels (or operating 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 (or single-level) 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 CO₂ pollutant concentration monitor, each 
CO₂ monitoring system that uses an O₂ monitor to 
determine CO₂ 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 O₂ 
monitor used to determine CO₂ concentration, the 
CO₂ reference method shall be used for the RATA; and
* * * * *
    (d) * * *
    (2) * * *
    (iii) * * * However, if the linearity test is performed within 168 
unit or stack operating hours but is either failed or aborted due to a 
problem with the CEMS or like-kind replacement analyzer, then all of 
the conditionally valid data are invalidated back to the hour of the 
probationary calibration error test, and data from the non-redundant 
backup CEMS or from the primary monitoring system of which the like-
kind replacement analyzer is a part remain invalid until the hour of 
completion of a successful linearity test. Notwithstanding this 
requirement, the conditionally valid data status may be re-established 
after a failed or aborted linearity check, if corrective action is 
taken and a calibration error test is subsequently passed. However, in 
no case shall the use of conditional data validation extend for more 
than 168 unit or stack operating hours beyond the date and time of the 
original probationary calibration error test when the analyzer was 
brought into service.
* * * * *
    (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 quality-assurance testing, 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) * * *
    (1) Monitoring plan. The designated representative shall submit a 
monitoring plan in accordance with Sec. 75.53 and 75.62.
* * * * *
    (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 on the date of submittal 
(consistent with the definition of "submit" in 
Sec. 72.2 of this chapter) of a complete certification 
application, 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_X mass emissions reduction 
program under subpart H of this part prior to the applicable 
commencement date specified in Sec. 75.19(a)(2)(i).
    (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 Sec. 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 40433]]

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 SO₂, 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_X 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 
CO₂ 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_X 
mass reduction program where the owner or operator intends to monitor 
NO_X mass emissions with a NO_X pollutant 
concentration monitor and a flow monitoring system, substitute for 
NO_X concentration using the maximum potential concentration 
of NO_X, 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)(i), 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), on an annual or ozone season basis, as 
applicable.

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 operations (e.g.," after the words 
"higher sulfur fuel(s)" in the first sentence, and by 
adding a closing parenthesis after the words "short-term 
testing" in the first sentence;
    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 SO₂ RATA requirements of this part" to read 
"exempted from the SO₂ RATA requirements of this part 
under paragraphs (a)(6) or (a)(7) of this section"; and
    d. In paragraph (e)(2) by revising the word "another" 
to read "other".

    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 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_X 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 revising the period at the end of the 
paragraph to read "; 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 
H₂O) 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 Sec. 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 (CO₂ or 
O₂) 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 paragraph (c) heading introductory text, and paragraph 
(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 SO₂, 
CO₂, O₂ 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_X-
diluent, NO_X 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_X emission rate or NO_X 
concentration data (load ranges or operational bins used). The 
procedures in this paragraph apply to affected units for which load-
based 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_X and flow rate data. For each hour 
of missing volumetric flow rate data, NO_X emission rate 
data, or NO_X

[[Page 40434]]

concentration data used to determine NO_X 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_X emission rates, or NO_X 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_X emission rate or the maximum potential 
NO_X 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_X emission rate 
or NO_X concentration data (operational bins not used). The 
procedures in this paragraph, (d), 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_X emission rate 
data, or NO_X concentration data used to determine 
NO_X 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_X emission rates or 
NO_X concentrations.
    (2) Whenever no prior quality-assured flow rate, NO_X 
emission rate, or NO_X 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_X 
emission rate or the maximum potential NO_X 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 and paragraph (a)(2) 
(except for Equation 9);
    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. In paragraph (a)(3) by revising the first three sentences.
    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 SO₂, 
CO₂, O₂ 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 begin calculating the percent 
monitor data availability as described in paragraph (a)(1) of this 
section, and shall, upon completion of the first 720 quality-assured 
monitor operating hours, record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for each monitored parameter. Similarly, following initial 
certification of the required NO_X-diluent, NO_X 
concentration, or flow monitoring system(s) at a unit or stack 
location, the owner or operator shall begin calculating the percent 
monitor data availability as described in paragraph (a)(1) of this 
section, and shall, upon completion of the first 2,160 quality-assured 
monitor operating hours, record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for each monitored parameter. 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 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.
* * * * *
    (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 operating hours in the previous three years (26,280 clock hours), 
replace the words "during previous 8,760 unit operating 
hours" in the numerator of Equation 9 with "in the previous 
three years" and replace "8,760" in the denominator 
of Equation 9 with "total unit operating hours in the previous 
three years." * * *
* * * * *

    22. Section 75.33 is amended by:
    a. Revising paragraph (a), removing Tables 1 and 2 after paragraph 
(a), and revising paragraph (c) introductory text;
    b. Adding paragraphs (b)(5), (b)(6), (b)(7), (c)(7), (c)(8), 
(c)(9), (d), and (e), including new Tables 3 and 4;
    c. In paragraph (c)(1) introductory text and paragraph (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
    h. In paragraph (c)(6) by revising the words "for either the 
corresponding load range or a higher load range" to read 
"at either the corresponding load range (or a higher load range) 
or at the corresponding operational bin".
    The revisions and additions read as follows:

Sec. 75.33  Standard missing data procedures for 
SO₂, NO_X and flow rate.

    (a) Following initial certification of the required SO₂, 
NO_X, and flow rate monitoring system(s) at a particular unit

[[Page 40435]]

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 SO₂) or the first 2,160 quality assured monitor 
operating hours (for flow, NO_X emission rate, or 
NO_X 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 
(SO₂) and Table 2 of this section (NO_X, flow). 
The owner or operator may either implement the provisions of paragraphs 
(b) and (c) of this section on a non-fuel-specific basis, or may, as 
described in paragraphs (b)(5), (b)(6), (c)(7) and (c)(8) of this 
section, provide fuel-specific substitute data values. 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) For units that combust more than one type of fuel, the owner or 
operator may opt 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.
    (6) Use the following guidelines to implement paragraphs (b)(1) 
through (b)(4) of this section on a fuel-specific basis:
    (i) Separate the historical, quality-assured SO₂ 
concentration data according to the type of fuel combusted;
    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest SO₂ emission rate (e.g., if diesel oil and pipeline 
natural gas are co-fired, count co-fired hours as oil-burning hours), 
or separate the co-fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(b)(4) of this section, determine a separate, fuel-specific maximum 
potential SO₂ concentration (MPC) value for each type of 
fuel 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. For co-firing, the MPC 
value shall be based on the fuel with the highest SO₂ 
emission rate. The exact methodology used to determine each fuel-
specific MPC value shall be documented in the monitoring plan for the 
unit or stack; and
    (iv) For missing data periods that require 720-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data 
values. Otherwise, use data for the fuel with the highest 
SO₂ emission rate to provide substitute data values for co-
fired missing data hours.
    (7) Table 1 summarizes the provisions of paragraphs (b)(1) through 
(b)(6) of this section.
    (c) Volumetric flow rate, NO_X emission rate and NO_X 
concentration data. Use the procedures in this paragraph to provide 
substitute NO_X 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_X emission rate data, or NO_X 
concentration data used to determine NO_X mass emissions:
* * * * *
    (4) * * * In addition, when non-load-based operational 
bins are used, the owner or operator shall substitute 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, (c)(5), does not apply to non-load-based, 
affected units using operational bins. * * *
* * * * *
    (7) This paragraph (c)(7) does not apply to affected units using 
non-load-based operational bins. For units that combust more than one 
type of fuel, the owner or operator may opt to implement the missing 
data routines in paragraphs (c)(1) through (c)(6) 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
    (8) This paragraph, (c)(8), does not apply to affected units using 
non-load-based operational bins. Use the following guidelines to 
implement paragraphs (c)(1) through (c)(6) of this section on a fuel-
specific basis:
    (i) Separate the historical, quality-assured NO_X 
emission rate, NO_X concentration, or flow rate data 
according to the type of fuel combusted;
    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest NO_X emission rate, NO_X concentration or 
flow rate, or separate the co-fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(c)(4) of this section, a separate, fuel-specific maximum potential 
concentration (MPC), maximum potential NO_X 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 Sec. 72.2 of this chapter and with section 
2.1.2.1 or 2.1.4.1 of appendix A to this part. For co-firing, the MPC, 
MER or MPF value shall be based on the fuel with the highest emission 
rate or flow rate (as applicable). The exact methodology used to 
determine each fuel-specific MPC, MER or MPF value shall be documented 
in the monitoring plan for the unit or stack.
    (iv) For missing data periods that require 2,160-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data 
values. Otherwise, use data for the fuel with the highest 
NO_X emission rate, NO_X concentration or flow rate 
(as applicable) to provide substitute data values for co-fired missing 
data hours. Tables 1 and 2 follow.

[[Page 40436]]

Table 1. Missing Data Procedure for SO₂ CEMS, CO₂ CEMS, Moisture CEMS and Diluent (CO₂ or O₂) Monitors for
                                            Heat Input Determination
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                       Duration (N) of CEMS
     Monitor data availability                outage                    Method               Lookback  period
             (percent)                  (hours) \2\
----------------------------------------------------------------------------------------------------------------
95 or more.........................  N &le; 24                Average...................  HB/HA.
                               N &gt; 24                For SO₂, CO₂, and
                                                               H₂O **, the greater
                                                               of:.
                                                  Average.............  HB/HA.
                                                  90th percentile.....  720 hours *.
                                                  For O₂ and H₂Ox , the
                                                               lesser of:.
                                                  Average.............  HB/HA.
                                                  10th percentile.....  720 hours *.
90 or more, but below 95...........  N &le; 8                 Average...................  HB/HA.
                               N &gt; 8                 For SO₂, CO₂, and H₂O**,
                                                               the greater of:.
                                                  Average.............  HB/HA.
                                                  95th percentile.....  720 hours *.
                                                  For O₂ and H₂Ox, the
                                                               lesser of:.
                                                  Average.............  HB/HA.
                                                  5th percentile......  720 hours *.
80 or more, but below 90...........  N &gt; 0                 For SO₂, CO₂, and H₂O**,..
                                                  Maximum               720 hours *.
                                                               value \1\.
                                                  For O₂ and H₂Ox:..........
                                                  Minimum               720 hours *.
                                                               value \1\.
Below 80...........................  N &gt; 0                 Maximum potential
                                                               concentration or % (for
                                                               SO₂, CO₂, and
                                                               H₂O **) or.
                                                  Minimum potential           None.
                                                               concentration or % (for
                                                               O₂ and H₂Ox).
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
 *Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-
  specific. For units that report data only for the ozone season, include only quality assured monitor operating
  hours within the ozone season in the lookback period. Use data from no earlier than 3 years prior to the
  missing data period.
\1\ Where a unit with add-on SO₂ emission controls can demonstrate that the controls are operating
  properly, as provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission
  rate from the previous 720 operating hours.
\2\ During unit operating hours.
\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_X 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_X emission rate.


Table 2. Load-Based Missing Data Procedure for NO_X-Diluent CEMS, NO_X Concentration CEMS and Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                 Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                  Duration (N) of
   Monitor data availability        CEMS outage              Method          Lookback  period     Load  ranges
           (percent)             (hours) \2\
----------------------------------------------------------------------------------------------------------------
95 or more....................  N &le; 24            Average..............  2160               Yes.
                                                                             hours *.
                          N &gt; 24            The greater of:......
                                         Average........  HB/HA............  No.
                                         90th percentile  2160.              Yes.
                                                                             hours *.
90 or more, but below 95......  N &le; 8             Average..............  2160               Yes.
                                                                             hours *.
                          N&gt;8               The greater of.......
                                         Average........  HB/HA............  No
                                         95th percentile  2160               Yes.
                                                                             hours *.
80 or more, but below 90......  N &gt; 0             Maximum                2160               Yes.
                                                      value \1\.       hours *.
Below 80......................  N &gt; 0             Maximum NO_X emission   None.............  No.
                                                      rate; or maximum
                                                      potential NO_X NO_X
                                                      concentration; or
                                                      maximum potential
                                                      flow rate.
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
· Quality-assured, monitor operating hours, using data at the corresponding load range
  ("load bin") for each hour of the missing data period. May be either fuel-specific or non-fuel-
  specific. For units that report data only for the ozone season, include only quality assured monitor operating
  hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the
  missing data period.
\1\ Where a unit with add-on NO_X emission controls can demonstrate that the controls are operating
  properly, as provided in Sec. 75.34, the unit may, upon approval, use the maximum controlled emission
  rate from the previous 720 operating hours. Alternatively, units with add-on controls that report NO_X mass
  emissions on a year-round basis under subpart H of this part may use separate ozone season and non-ozone
  season databases to provide substitute data values, as described in Sec. 75.34(a)(2).
\2\ During unit operating hours.

[[Page 40437]]

    (9) The load-based provisions of paragraphs (c)(1) through (c)(8) 
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), and (c)(6) of this section, are presented in 
Table 4 of this section.
    (d) Non-load-based NO _X emission rate and NO_X 
concentration data. Use the procedures in this paragraph to provide 
substitute NO_X 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_X emission rate data, or 
NO_X concentration data used to determine NO_X 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_X emission rates or NO_X 
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, 
for each missing hour, the 90th percentile NO_X emission rate 
or the 90th percentile NO_X 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).
    (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_X emission rates or NO_X 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, for each missing hour, the 95th percentile hourly flow rate 
or the 95th percentile NO_X emission rate or the 95th 
percentile NO_X 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).
    (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_X emission rate or the maximum hourly 
NO_X concentration 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_X 
emission rate, as defined in Sec. 72.2 of this chapter, or the 
maximum potential NO_X 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_X emission rate or the maximum potential 
NO_X 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_X concentration data or NO_X emission rate data 
exist for the corresponding operational bin, the owner or operator 
shall substitute, as applicable, either the maximum potential 
NO_X emission rate, as defined in Sec. 72.2 of this 
chapter, or the maximum potential NO_X concentration, as 
defined in section 2.1.2.1 of appendix A to this part.
    (6) Table 3 of this section summarizes the provisions of paragraphs 
(d)(1) through (d)(5) 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 unit that does not produce electrical or thermal output, 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, 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), and (c)(8) are not applicable; and
    (iv) In paragraph (c)(6), the words, "for either the 
corresponding load range (or a higher load range) or at 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_X-Diluent CEMS and NO_X Concentration CEMS
----------------------------------------------------------------------------------------------------------------
                    Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                      Duration (N) of CEMS
Monitor data availability  (percent)   outage  (hours)\1\              Method                Lookback  period
----------------------------------------------------------------------------------------------------------------
95 or more..........................  N &le; 24             Average....................  2160 hours*
                                N &gt; 24             90th percentile............  2160 hours*
90 or more, but below 95............  N &le; 8              Average....................  2160 hours*
                                N &gt; 8              95th percentile............  2160 hours*

[[Page 40438]]

80 or more, but below 90............  N &gt; 0              Maximum value..............  2160 hours*
Below 80, or operational bin          N &gt; 0              Maximum NO_X emission rate    None
 indeterminable.                                             or maximum potential NO_X
                                                             concentration.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and
  data at the corresponding operational bin are used to provide substitute data values. If operational bins are
  not used, the lookback period is the previous 2,160 quality-assured monitor operating hours. For units that
  report data only for the ozone season, include only quality-assured monitor operating hours within the ozone
  season in the lookback period. Use data from no earlier than three years prior to the missing data period.
\1\During unit operation.

                     Table 4. Non-load-based Missing Data Procedure for Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                    Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                      Duration (N) of CEMS
 Monitor data availability (percent)   outage  (hours)\1\              Method                Lookback  period
----------------------------------------------------------------------------------------------------------------
95 or more..........................  N &le; 24             Average....................  2160 hours*
                                N &gt; 24             The greater of:............  
                                                            Average....................  HB/HA
                                                            90th percentile............  2160 hours*
90 or more, but below 95............  N &le; 8              Average....................  2160 hours*
                                N &gt; 8              The greater of:............  
                                                            Average....................  HB/HA
                                                            95th percentile............  2160 hours*
80 or more, but below 90............  N &gt; 0              Maximum value..............  2160 hours*
Below 80, or operational bin          N &gt; 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 and data at the corresponding operational bin are used to provide substitute data values. If
  operational bins are not used, the lookback period is the previous 2,160 quality-assured, monitor operating
  hours. For units that report data only for the ozone season, include only quality assured monitor operating
  hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the
  missing data period.
\1\ During unit operation.

    23. Section 75.34 is amended by:
    a. Revising paragraph (a) introductory text, and paragraphs (a)(1) 
and (d);
    b. Redesignating paragraphs (a)(2) and (a)(3) as paragraphs (a)(3) 
and (a)(4), respectively;
    c. Adding a new paragraph (a)(2);
    d. In the second sentence of newly redesignated paragraph (a)(4) by 
removing the words "Sec. 75.55(b) or" and ", 
as applicable"; and
    e. In paragraph (c) by revising the word 
"NO_X2" to read "NO_X".
    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 
SO₂ and/or NO_X emission controls shall use one of 
the options in paragraphs (a)(1), (a)(2) or (a)(4) of this section for 
each hour in which quality-assured data from the outlet SO₂ 
and/or NO_X monitoring system(s) are not obtained, and shall 
document which option is selected in the monitoring plan required under 
Sec. 75.53. If the option in paragraph (a)(1) or (a)(2) is 
selected, the owner or operator may also use the petition provision in 
paragraph (a)(3) of this section.
    (1) The owner or operator may use the missing data substitution 
procedures specified in Sec. 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 SO₂ or NO_X 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 SO₂ or NO_X add-on emission controls has been 
maintained, the owner or operator shall substitute (as applicable) the 
maximum potential NO_X concentration (MPC) as defined in 
section 2.1.2.1 of appendix A to this part, the maximum potential 
NO_X emission rate, as defined in Sec. 72.2 of this 
chapter, or the maximum potential concentration for SO₂, as 
defined by section 2.1.1.1. Alternatively, for SO₂ or 
NO_X, the owner or operator may substitute, if available, the 
hourly SO₂ or NO_X 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

[[Page 40439]]

certification statement, verifying the proper operation of the 
SO₂ or NO_X add-on emission control for each 
missing data period in which the missing data procedures of 
Sec. 75.31 through 75.33 were applied; or
    (2) This paragraph, (a)(2), applies only to a unit which, as 
provided in Sec. 75.74(a) or Sec. 75.74(b)(1), reports 
NO_X mass emissions on a year-round basis under a state or 
Federal NO_X mass emissions reduction program that adopts the 
emissions monitoring provisions of this part. If the add-on 
NO_X emission controls installed on such a unit are operated 
only during the ozone season or are operated in a more efficient manner 
during the ozone season than outside the ozone season, the owner or 
operator may implement the missing data provisions of paragraph (a)(1) 
of this section in the following alternative manner:
    (i) The historical, quality-assured NO_X emission rate or 
NO_X concentration data may be separated into two categories, 
i.e., data recorded inside the ozone season and data recorded outside 
the ozone season;
    (ii) For the purposes of the missing data lookback periods 
described under Sec. 75.33(c)(1), (c)(2) and (c)(3), the 
substitute data values shall be taken from the appropriate database, 
depending on the date(s) and hour(s) of the missing data period. That 
is, if the missing data period occurs inside the ozone season, the 
ozone season data shall be used to provide substitute data. If the 
missing data period occurs outside the ozone season, data from outside 
the ozone season shall be used to provide substitute data.
    (iii) A missing data period that begins outside the ozone season 
and continues into the ozone season shall be considered to be two 
separate missing data periods, one ending on April 30, hour 23, and the 
other beginning on May 1, hour 00;
    (iv) For missing data hours outside the ozone season, the 
procedures of Sec. 75.33 may be applied unconditionally, i.e, 
documentation of the operational status of the emission controls is not 
required in order to apply the standard missing data routines.
* * * * *
    (d) In order to implement the options in paragraphs (a)(1) and 
(a)(3) of this section, the owner or operator shall keep records of 
information as described in Sec. 75.58(b)(3) to verify the 
proper operation of all add-on SO₂ or NO_X 
emission controls, during all periods of SO₂ or 
NO_X emission missing data. If the owner or operator elects 
to implement the missing data option in paragraph (a)(2) of this 
section, the records in Sec. 75.58(b)(3) are required to be 
kept only for the ozone season. 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. 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 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 CO₂.

    (a) The owner or operator of a unit with a CO₂ 
continuous emission monitoring system for determining CO₂ 
mass emissions in accordance with Sec. 75.10 (or an 
O₂ monitor that is used to determine CO₂ 
concentration in accordance with appendix F to this part) shall 
substitute for missing CO₂ 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 CO₂ 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 
CO₂ pollutant concentration data or substitute 
CO₂ data for heat input determination, as applicable, 
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 CO₂ 
concentration or substitute CO₂ data for heat input 
determination, as applicable, in accordance with the procedures in 
Sec. 75.33(b) except that the term "CO₂ 
concentration" shall apply rather than "SO₂ 
concentration," the term "CO₂ pollutant 
concentration monitor" or "CO₂ diluent 
monitor" shall apply rather than "SO₂ pollutant 
concentration monitor," and the term "maximum potential 
CO₂ concentration, as defined in section 2.1.3.1 of appendix 
A to this part" shall apply, rather than "maximum potential 
SO₂ 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, by removing the words "On and 
after April 1, 2000" in the third sentence and capitalizing 
"When" to begin that sentence, and by removing the final 
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:

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 CO₂ or O₂ 
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 CO₂ or O₂ 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).
    (c) [Reserved]
* * * * *

    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" 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

[[Page 40440]]

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 SO₂ emissions, CO₂ 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 
"SO₂ concentration," the term "moisture 
monitoring system" shall apply rather than "SO₂ 
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 
SO₂ concentration;" or
* * * * *

    27. Section 75.41 is amended by:
    a. In paragraph (b)(2)(v)(B) by adding the words "(Eq. 
22)" immediately before "where"; and
    b. By revising Equation 27 in paragraph (c)(2)(ii).
    The revisions and additions read as follows:

Sec. 75.41  Precision criteria.

* * * * *
    (c) * * *
    (2) * * *
    (ii) * * *
    [GRAPHIC]
[TIFF OMITTED]
TR12JN02.007
    
* * * * *

    28. Section 75.53 is amended by:
    a. Removing and reserving paragraphs (c) and (d);
    b. Revising paragraphs (a)(1), (e)(1)(viii), and (f)(1)(i)(F);
    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) introductory text by adding the words 
"(or equivalent facility ID number assigned by EPA, if the 
facility does not have an ORISPL number)" after the words 
"Data Base";
    e. In paragraph (e)(1)(i)(D) by adding the words "/emergency/
startup" after the words "primary/secondary";
    f. In paragraph (e)(1)(i)(E) by adding the words "primary/
secondary controls indicator;" after the words "(if 
applicable);";
    g. In paragraph (e)(1)(ix) by revising the words "Part 75 
monitoring" to read "Monitoring" and by revising the 
words "reporting year, and 767 reporting indicator" to read 
"ARP/Subpart H facility ID number or ORISPL number (as 
applicable), reporting year, and 767 reporting indicator (or 
equivalent)";
    h. In paragraph (e)(1)(xii) introductory text by revising the words 
"For each unit or common stack (except for peaking units)" 
to read "Unless otherwise specified in section 6.5.2.1 of 
appendix A to this part, for each unit or common stack";
    i. In paragraph (e)(1)(xii)(A) and (B) by adding the words ", 
or ft/sec (as applicable)" to the end of each paragraph, and by 
adding a comma after "megawatts" in each paragraph;
    j. In paragraph (e)(1)(xii)(D) by revising the first occurrence of 
the word "load" to read "data" and by adding 
the words "(or operating)" after each other occurrence of 
the word "load" and in paragraphs (e)(1)(xii)(B), (C), and 
(E) by adding the words "or operating" after each occurence 
of the word "load";
    k. In paragraph (f)(2)(i)(F) by adding the word "rate" 
after the word "input" and the word "emission" 
after the word "NO_X";
    l. In paragraph (f)(2)(i)(H) by adding the words "or ozone 
season" after the word "year" and by revising the 
word "part" to read "chapter";
    m. In paragraph (f)(5) introductory text by adding the words 
"that accompanies the initial certification application" to 
the end of the paragraph;
    n. In paragraph (f)(5)(i) by revising the second sentence and by 
adding a third sentence and new paragraphs (f)(5)(i)(A) through (F);
    o. In paragraph (f)(5)(ii)(C) by revising the words "natural 
gas or" to read "gaseous fuel(s) and/or" in two 
occurrences: and
    p. In paragraph (f)(5)(ii)(E) by adding the words ", 
estimated" after the word "actual".
    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.
    (c) [Reserved]
    (d) [Reserved]
    (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 for daily or annual fuel sampling for sulfur 
content, as applicable.
* * * * *
    (5) * * *
    (i) * * * This report will include either the previous 
three years actual or projected emissions. The following items should 
be included:
    (A) Current calendar year of application;
    (B) Type of qualification;
    (C) Years one, two, and three;
    (D) Annual or ozone season measured, estimated or projected 
NO_X mass emissions for years one, two, and three;
    (E) Annual measured, estimated or projected SO₂ mass 
emissions for years one, two, and three; and
    (F) 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.

    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)(iv);
    e. Amending paragraph (d)(6) and (d)(7) by removing the words 
"either",

[[Page 40441]]

"hundredth or", and "prior to April 1, 2000 and 
rounded to the nearest thousandth on and after April 1, 2000".
    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
------------------------------------------------------------------------
                         Hourly emissions/flow measurement or estimation
         Code                                method
------------------------------------------------------------------------
1.....................  Certified primary emission/flow monitoring
                         system.
2.....................  Certified backup emission/flow monitoring
                         system.
3.....................  Approved alternative monitoring system.
4.....................  Reference method:
                  SO₂: Method 6C.
                  Flow: Method 2 or its allowable alternatives
                         under appendix A to part 60 of this chapter.
                  NO_X: Method 7E.
                  CO₂ or O₂: Method 3A.
5.....................  For units with add-on SO₂ and/or NO_X emission
                         controls: SO₂ concentration or NO_X emission
                         rate estimate from Agency preapproved
                         parametric monitoring method.
6.....................  Average of the hourly SO₂ concentrations, CO₂
                         concentrations, O₂ concentrations, NO_X
                         concentrations, flow rates, moisture
                         percentages or NO_X emission rates for the hour
                         before and the hour following a missing data
                         period.
7.....................  Initial missing data procedures used. Either:
                         (a) the average of the hourly SO₂
                         concentration, CO₂ concentration, O₂
                         concentration, or moisture percentage for the
                         hour before and the hour following a missing
                         data period; or (b) the arithmetic average of
                         all NO_X concentration, NO_X emission rate, or
                         flow rate values at the corresponding load
                         range (or a higher load range), or at the
                         corresponding operational bin (non-load-based
                         units, only); or (c) the arithmetic average of
                         all previous NO_X concentration, NO_X emission
                         rate, or flow rate values (non-load- based
                         units, only).
8.....................  90th percentile hourly SO₂ concentration, CO₂
                         concentration, NO_X concentration, flow rate,
                         moisture percentage, or NO_X emission rate or
                         10th percentile hourly O₂ concentration or
                         moisture percentage in the applicable lookback
                         period (moisture missing data algorithm depends
                         on which equations are used for emissions and
                         heat input).
9.....................  95th percentile hourly SO₂ concentration, CO₂
                         concentration, NO_X concentration, flow rate,
                         moisture percentage, or NO_X emission rate or
                         5th percentile hourly O₂ concentration or
                         moisture percentage in the applicable lookback
                         period (moisture missing data algorithm depends
                         on which equations are used for emissions and
                         heat input).
10....................  Maximum hourly SO₂ concentration, CO₂
                         concentration, NO_X concentration, flow rate,
                         moisture percentage, or NO_X emission rate or
                         minimum hourly O₂ concentration or moisture
                         percentage in the applicable lookback period
                         (moisture missing data algorithm depends on
                         which equations are used for emissions and heat
                         input).
11....................  Average of hourly flow rates, NO_X concentrations
                         or NO_X emission rates in corresponding load
                         range, for the applicable lookback period. For
                         non-load-based units, report either the average
                         flow rate, NO_X concentration or NO_X emission
                         rate in the applicable lookback period, or the
                         average flow rate or NO_X value at the
                         corresponding operational bin (if operational
                         bins are used).
12....................  Maximum potential concentration of SO₂, maximum
                         potential concentration of CO₂, maximum
                         potential concentration of NO_X maximum
                         potential flow rate, maximum potential NO_X
                         emission rate, maximum potential moisture
                         percentage, minimum potential O₂ concentration
                         or minimum potential moisture percentage, as
                         determined using Sec. 72.2 of this
                         chapter and section 2.1 of appendix A to this
                         part (moisture missing data algorithm depends
                         on which equations are used for emissions and
                         heat input).
13....................  [Reserved]
14....................  Diluent cap value (if the cap is replacing a CO₂
                         measurement, use 5.0 percent for boilers and
                         1.0 percent for turbines; if it is replacing an
                         O₂ measurement, use 14.0 percent for boilers
                         and 19.0 percent for turbines).
15....................  [Reserved]
16....................  SO₂ 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 SO₂ concentration, NO_X
                         concentration, percent moisture, or NO_X
                         emission rate replaced with zero.
22....................  Hourly average SO₂ or NO_X concentration,
                         measured by a certified monitor at the control
                         device inlet (units with add-on emission
                         controls only).
23....................  Maximum potential SO₂ concentration, NO_X
                         concentration, CO₂ concentration, NO_X emission
                         rate or flow rate, or minimum potential O₂
                         concentration or moisture percentage, for an
                         hour in which flue gases are discharged through
                         an unmonitored bypass stack.
25....................  Maximum potential NO_X emission rate (MER). (Use
                         only when a NO_X 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.
------------------------------------------------------------------------

* * * * *

    33. Section 75.58 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraphs (b)(1)(i) and (c) introductory text 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";
    d. Revising paragraph (b)(3) introductory text;
    e. In paragraph (b)(3)(i) by adding the words ", for each 
hour of missing SO₂ or NO_X emission data," 
after the word "demonstrate";
    f. In paragraph (b)(3)(ii) by adding the words ", for each 
hour of missing SO₂ or NO_X emission data," 
after the word "indicating";

[[Page 40442]]

    g. In paragraphs (b)(3)(iii) and (b)(3)(iv) by revising the 
reference to "Sec. 75.34(a)(2)" to read 
"Sec. 75.34(a)(3)";
    h. Adding a period to the end of paragraph (c)(7)(ii);
    i. In paragraph (d) introductory text by removing the words 
"paragraph Sec. 75.54(d) or";
    j. In paragraph (e)(1) by removing the words 
"Sec. 75.54(c)(1) and (c)(3) or";
    k. In paragraph (f) introductory text by removing the words 
"Sec. 75.54(b) through (e) or"; and
    l. In paragraph (f)(1)(iii) by adding the words "other 
gaseous fuel," after the words "natural gas,".
    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) Except as otherwise provided in Sec. 75.34(d), for 
units with add-on SO₂ or NO_X emission controls 
following the provisions of Sec. 75.34(a)(1), (a)(2) or (a)(3), 
the owner or operator shall record:
* * * * *

    34. Section 75.59 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraph (a)(1)(vii), by revising "Calibration" 
to read "Reference signal or calibration";
    c. In paragraph (a)(5)(ii)(E) by removing both occurrences of the 
word "load" and by adding the word "operating" 
before the word "levels";
    d. In paragraph (a)(5)(ii)(F) by adding the words "(or 
operating level)" before the word "indicator";
    e. In paragraph (a)(5)(ii)(L) by adding the words ", except 
for units that do not produce electrical or thermal output" after 
the words "lb/hr)";
    f. In paragraph (a)(5)(iii)(E) by adding the words "(or 
operating)" before both of the two occurrences of the word 
"level" and by adding the words ", or as otherwise 
specified by the Administrator, for units that do not produce 
electrical or thermal output" after the words "lb/
hr";
    g. In the second sentence of paragraph (a)(7) by adding the words 
"of this section" after the words "through 
(a)(7)(vi)";
    h. In paragraph (a)(7)(ii)(A) by removing the word 
"load";
    i. Revising paragraphs (a)(7)(ii)(P) and (a)(7)(iii)(F);
    j. In paragraph (a)(10)(i)(E) by revising the reference to 
"(a)(7)(iii)(A)" to read "(a)(7)(iii)";
    k. In paragraph (a)(12)(v) introductory text by adding the words 
"(or single-level)" before the word "flow";
    l. In paragraphs (a)(12)(v)(C) and (E) by adding the words 
"(or operating)" before the word "level", and 
by, in paragraph (C), removing the period at the end of the paragraph 
and adding a semicolon in its place;
    m. In paragraph (a)(12)(v)(D) by adding the words "(or 
operating level)" before the word "data";
    n. In paragraph (b)(2)(v) by adding the word "level" 
after the word "high";
    o. In paragraph (b)(4)(ii)(K) by removing the word 
"and" after the semicolon;
    p. In paragraph (b)(4)(ii)(L) by removing the period and adding in 
its place "; and";
    q. Adding paragraph (b)(4)(ii)(M);
    r. In paragraph (c)(1) by removing the words 
"Sec. 75.55(b) or";
    s. In paragraph (d)(1) introductory text by revising the word 
"under" to read "using the procedures of";
    t. In paragraph (d)(1)(xi) by adding the word "and" 
after the semicolon and in paragraph (d)(1)(xii) by removing the 
semicolon and adding a period in its place;
    u. Removing paragraphs (d)(1)(xiii) through (d)(1)(xvi);
    v. Redesignating existing paragraph (d)(2) as (d)(3) and adding a 
new paragraph (d)(2); and
    w. In newly designated paragraph (d)(3)(x) by revising the words 
"Sec. 75.19(c)(1)(iv)(B)(1) and (3)" to read 
"Sec. 75.19(c)(1)(iv)(B)(1)".
    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) * * *
    (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 H₂O) or the average of the square roots of the 
velocity differential pressures at the traverse point ((inches of 
H₂O)1/2);
* * * * *
    (b) * * *
    (4) * * *
    (ii) * * *
    (M) Number of hours excluded due to co-firing.
* * * * *
    (d) * * *
    (2) For each single-load or multiple-load appendix E test, record 
the following:
    (i) The three-run average NO_X emission rate for each 
load level;
    (ii) An indicator that the average NO_X emission rate is 
the highest NO_X average emission rate recorded at any load 
level of the test (if appropriate);
    (iii) The default NO_X emission rate (highest three-run 
average NO_X emission rate at any load level), multiplied by 
1.15, if appropriate;
    (iv) An indicator that the add-on NO_X 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:
    a. In paragraph (b)(6), adding the words "in writing (or by 
electronic mail)" after the words "If requested"; and
    b. Adding paragraph (b)(7).
    The revisions and additions read as follows:

Sec. 75.60  General provisions.

* * * * *
    (b) * * *
    (7) Routine appendix E retest reports. If requested in writing (or 
by electronic mail) by the applicable EPA Regional Office, appropriate 
State, and/or appropriate local air pollution control agency, the 
designated representative shall submit a hardcopy report 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) introductory text by removing the words 
"and except for testing only of the data acquisition and handling 
system" from 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 heading and first 
sentence, and by adding a new sentence after the first sentence;
    c. In paragraph (a)(1)(ii) by revising the word "and" 
to read ", and partial" in the heading, and, in the first 
sentence, by adding the word

[[Page 40443]]

"required" after the word "retesting", and 
revising the words "recertification under Sec. 75.20(b), 
notice of testing" to read "partial recertification testing 
required under Sec. 75.20(b)(2), notice of the date of any 
required RATA testing or any required retesting under section 2.3 in 
appendix E to this part";
    d. In paragraph (a)(1)(iii) by adding the words "or 
recertification" after each occurrence of the word 
"certification" and by adding the words "must be 
aborted, or" after the words "was failed or";
    e. 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;
    f. In the first sentence of paragraph (a)(2) introductory text by 
adding the words ", or becomes affected," after the words 
"commercial operation";
    g. In paragraph (a)(2)(i) by adding the words "or becomes 
affected" after the words "commences commercial 
operation";
    h. In paragraph (a)(2)(ii) by adding the words "or becomes 
affected," after both occurrences of the words "commences 
commercial operation" and by removing the comma between the words 
"or" and "the date";
    i. In paragraph (a)(4) by removing "(a)" after the 
second and third occurrences of "Sec. 75.4";
    j. Revising the heading and the first sentence of paragraph (a)(5) 
introductory text;
    k. In paragraph (a)(5)(ii) by adding the words ", appendix E 
retest, or low mass emissions unit retest" before the word 
"immediately"; and
    l. 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_X 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.
    (i) Notification of initial certification testing and full 
recertification. Initial certification test notifications and 
notifications of full recertification testing under 
Sec. 75.20(b)(2) shall be submitted not later than 21 days 
prior to the first scheduled day of certification or recertification 
testing. In emergency situations when full recertification testing is 
required following an uncontrollable failure of equipment that results 
in lost data, notice shall be sufficient if provided within 2 business 
days following the date when testing is scheduled.
* * * * *
    (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 or" before both occurrences of the word 
"recertification".
    The revisions and additions read as follows:

Sec. 75.62  Monitoring plan submittals.

    (a) * * *&ensp;
    (1) Electronic. Using the format specified in paragraph (c) of this 
section, the designated representative for an affected unit shall 
submit a complete, electronic, up-to-date monitoring plan file (except 
for hardcopy portions identified in paragraph (a)(2) of this section) 
to the Administrator as follows: no later than 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.
* * * * *
    38. Section 75.63 is amended by:
    a. In the section heading by removing the word 
"submittals";
    b. Revising paragraphs (a)(1)(i) and (a)(1)(ii), and removing 
paragraph (a)(1)(iii);
    c. In paragraph (a)(2) heading by adding the words "and 
diagnostic testing";
    d. 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)";
    e. In paragraph (a)(2)(ii) by adding, in the first sentence, the 
words "under Sec. 75.20(b)" after the word 
"tests" and the words "of this section" after 
the words "paragraph (b)(2)", and by revising, in the 
second sentence, the words "for submission to it of a hardcopy 
recertification" to read "to provide hardcopy 
recertification test data and results";
    f. In paragraph (a)(2)(iii) by adding the words "rather than 
recertification testing" after the words "are 
required";
    g. In paragraph (b)(1)(i), by removing the words 
"Sec. 75.53(c) and (d), or Sec. " and 
"as applicable,";
    h. In paragraph (b)(1)(ii) by removing the words 
"Sec. 75.56 or" and "as applicable,"; 
and
    i. In the first sentence of paragraph (b)(2)(i), by removing the 
words "Sec. 75.53(c) and (d), or 
Sec. " and "as applicable,".
    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). 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

[[Page 40444]]

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 
Sec. 75.53(f)(5)(i) and paragraph (b)(1)(i) of this section, 
and a hardcopy cover letter identifying the submittal as a low mass 
emissions unit certification application; 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) and Sec. 75.53(f)(5)(ii), 
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_X emission rate.
* * * * *

    39. Section 75.64 is amended by:
    a. In paragraph (a) introductory text by revising the first 
sentence, and by adding in the third sentence the words "or has 
been placed in long-term cold storage" after the words 
"Sec. 75.4(a)";
    b. In paragraph (a)(2) introductory text by revising the words 
"Sec. 75.53 through 75.59" to read 
Sec. 75.53 and Sec. 75.57 through 75.59";
    c. In paragraph (a)(2)(iii) by removing the words 
"Sec. 75.54(f) or";
    d. In paragraph (a)(2)(iv) by removing the words 
"Sec. 75.55(b)(3) or";
    e. In paragraph (a)(2)(vi) by removing the words 
"Sec. 75.54(g) or";
    f. In paragraph (a)(2)(vii) by removing the words 
"Sec. 75.56 or";
    g. In paragraph (a)(2)(viii) by adding a comma after the word 
"coefficients" and by removing the words 
"Sec. 75.56(a)(5)(vii), 
Sec. 75.56(a)(5)(ix),";
    h. In paragraph (a)(2)(xi) by removing the words 
"Sec. 75.56(a)(7) or";
    i. 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";
    j. Removing and reserving paragraphs (a)(2)(v), (a)(8), and (e);
    k. In paragraph (d) by revising the words "electronic or 
hardcopy" to read "(unless otherwise approved by the 
Administrator) electronic"; and
    l. In paragraph (f) by removing the words "modem and".
    The revisions and additions 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). * * *
* * * * *

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,";
    b. In paragraph (f) introductory text by revising the reference to 
"Sec. 75.34(a)(2)" to 
"Sec. 75.34(a)(3)"; and
    c. 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 paragraph (e);
    d. In paragraph (f) introductory text by revising the reference to 
"Sec. 75.74" to read 
"Sec. 75.74(c)(7)";
    e. In paragraph (f)(1) introductory text by revising the words 
"missing data procedures in subpart D of this part" to read 
"applicable missing data procedures in Sec. 75.31 
through 75.37";
    f. 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";
    g. In paragraphs (f)(1)(ii) and (iii) by removing the word 
"or" from the end of each paragraph;
    h. In paragraph (f)(1)(iii) by adding the word "rate" 
after the first occurrence of the word "input", revising 
the word "mmBtu" to read "mmBtu/hr", and by 
removing the words "or by an accepted monitoring system under 
appendix D to this part";
    i. 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;
    j. Adding new paragraph (f)(1)(v);
    k. In paragraph (g)(1) by adding the word "rate" after 
the words "and heat input";
    l. In paragraph (g)(2) by revising the words "of the unit 
under section 2.1 of Appendix A of" to read ", as defined 
in section 2.1.4.1 of appendix A to"; and
    m. Revising paragraph (g)(6).
    The revisions and additions read as follows:

Sec. 75.70  NO_X mass emissions provisions.

* * * * *
    (e) Quality assurance and quality control requirements. For units 
that use continuous emission monitoring systems to account for 
NO_X 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_X-diluent continuous emission monitoring systems, 
flow monitoring systems, NO_X 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) * * *
    (1) * * *
    (v) A valid, quality-assured hour of moisture data (in percent 
H₂O) 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 Sec. 75.11(b) or Sec. 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 "O₂" and 
"CO₂";
    b. In the second sentence of paragraph (a)(2) by removing the 
hyphens after the words "O₂" and 
"CO₂" and by revising the words "heat 
input, or, if applicable, use the procedures in appendix D to this 
part" to read "heat input rate";
    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"; and
    e. In paragraph (c)(2) by adding the word "rate" to the 
end of the first

[[Page 40445]]

sentence and by revising the second sentence; and
    f. In paragraph (d)(2) by revising the second sentence, by revising 
the words "paragraph (c) of this section or, if applicable, 
paragraph (e)" to read "paragraph (c)(1) or (c)(2)" 
in the third sentence, and by adding a new sentence at the end of the 
paragraph.
    The revisions and additions read as follows:

Sec. 75.71  Specific provisions for monitoring NO_X 
emission rate and heat input for the purpose of calculating 
NO_X mass emissions.

* * * * *
    (c) * * *
    (2) * * * However, for a common pipe configuration, the 
heat input rate apportionment provisions in section 2.1.2 of appendix D 
to this part shall not be used to meet the NO_X mass 
reporting provisions of this subpart, unless all of the units served by 
the common pipe are affected units and have similar efficiencies; or
* * * * *
    (d) * * *
    (2) * * * However, for a common pipe configuration, the 
heat input apportionment provisions in section 2.1.2 of appendix D to 
this part shall not be used to meet the NO_X mass reporting 
provisions of this subpart unless all of the units served by the common 
pipe are affected units and have similar efficiencies. * * * 
If the required CEMS are not installed and certified by that date, the 
owner or operator shall report hourly NO_X mass emissions as 
the product of the maximum potential NO_X 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.
* * * * *

    44. Section 75.72 is amended by:
    a. In the introductory paragraph to the section by revising the 
words "(in mmBtu/hr) and the hourly operating time (in hr)" 
to read "rate (in mmBtu/hr) and the unit or stack operating time 
(as defined in Sec. 72.2)";
    b. Revising paragraph (a)(1) introductory text and paragraph 
(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";
    e. By adding the words "and a diluent monitor" after 
the word "system" in the newly redesignated paragraph 
(a)(1)(iii)(B);
    f. In paragraph (a)(2) introductory text by adding the words 
", for purposes of heat input determination," after the 
words "from each unit and";
    g. In paragraph (a)(2)(ii)(A) by adding the word "rate" 
after the words "heat input";
    h. In paragraph (b)(1) introductory text by removing the semicolon 
and by adding the words ", for purposes of heat input 
determination," at the end of the paragraph;
    i. Revising paragraph (b)(1)(ii)(A);
    j. In paragraph (b)(2)(ii)(B) by adding the word "rate" 
after the words "heat input" in the first sentence and by 
revising the second sentence;
    k. In paragraph (b)(2)(iii) by adding the words ", in 
accordance with paragraph (a) of this section" after the word 
"purposes";
    l. Revising paragraph (c);
    m. Revising paragraph (d);
    n. In paragraph (e) introductory text by revising the first 
sentence, revising the words "appendix F of" to read 
"appendix F to" in the second sentence, and adding a new 
sentence between the first and second sentences;
    o. In paragraph (e)(1) introductory text by revising the second 
sentence and adding a new third sentence;
    p. 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)";
    q. In paragraph (e)(2) by adding the word "rate" after 
the words "heat input" in the first sentence and by 
removing the words "or a common stack" in the last 
sentence; and
    r. 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_X mass emissions.

* * * * *
    (a) * * *
    (1) Install, certify, operate, and maintain a NO_X-
diluent continuous emissions monitoring system and a flow monitoring 
system in the common stack, record the combined NO_X mass 
emissions for the units exhausting to the common stack, and, for 
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); or
    (ii) Install, certify, operate, and maintain a flow monitoring 
system and diluent monitor in the duct to the common stack from each 
unit; or
* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (A) Use the procedures in appendix D to determine heat input for 
that unit; however, for a common pipe configuration, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the NO_X mass reporting provisions 
of this subpart unless all of the units served by the common pipe are 
affected units and have similar efficiencies; and
* * * * *
    (2) * * *
    (ii) * * *
    (B) * * * However, for a common pipe serving both 
affected and non-affected units, the heat input rate apportionment 
provisions in section 2.1.2 of appendix D to this part shall not be 
used to meet the NO_X mass reporting provisions of this 
subpart. * * *
* * * * *
    (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_X-diluent continuous 
emissions monitoring system or NO_X concentration monitoring 
system, the owner and operator shall either:
    (1) Install, certify, operate, and maintain separate 
NO_X-diluent continuous emissions monitoring systems and flow 
monitoring systems on the main stack and the bypass stack and calculate 
NO_X mass emissions for the unit as the sum of the 
NO_X mass emissions measured at the two stacks;
    (2) Monitor NO_X mass emissions at the main stack using a 
NO_X-diluent CEMS and a flow monitoring system and measure 
NO_X mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for NO_X concentration, flow 
rate, and diluent gas concentration, or NO_X concentration 
and flow rate, and calculate NO_X 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_X-
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_X mass

[[Page 40446]]

emissions as follows. If the unit heat input is determined using a flow 
monitor and a diluent monitor, report NO_X mass emissions 
using the maximum potential NO_X emission rate, the maximum 
potential flow rate, and either the maximum potential CO₂ 
concentration or the minimum potential O₂ concentration (as 
applicable). The maximum potential NO_X emission rate may 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_X mass emissions as the product of the maximum 
potential NO_X 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_X-
diluent continuous emission monitoring system and a flow monitoring 
system in each of the multiple stacks and determine NO_X mass 
emissions from the affected unit as the sum of the NO_X 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_X mass 
emissions from the units using that stack;
    (2) Install, certify, operate, and maintain a NO_X-
diluent continuous emissions monitoring system and a flow monitoring 
system in each of the ducts that feed into the stack, and determine 
NO_X mass emissions from the affected unit using the sum of 
the NO_X 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_X-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) * * * The owner or operator may use a NO_X 
concentration monitoring system and a flow monitoring system to 
determine NO_X 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_X-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. In paragraph (a)(6) introductory text by removing the word 
"following", by revising the words "this 
paragraph" to read "Sec. 75.58(c)", and by 
removing the colon at the end of the paragraph and adding a period in 
its place;
    c. Removing paragraphs (a)(6)(i) through (a)(6)(vi) and paragraphs 
(e)(1)(i) and (e)(1)(ii);
    d. Adding new paragraphs (a)(8), (d)(6), (f)(1)(vii), and 
(f)(1)(viii);
    e. Revising the second and third sentences of paragraph (c)(3) and 
adding a new last sentence;
    f. Revising paragraph (e)(1); and
    g. 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) * * *
    (8) Formulas from monitoring plan for total NO_X 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 a complete, electronic, 
up-to-date monitoring plan file 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), 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.
    (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 (if applicable).
* * * * *
    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) 
introductory text;
    c. In paragraph (c)(2)(ii)(A), adding the words "(or 
operating level(s))" after the words "RATA load 
level(s)";
    d. Revising paragraphs (c)(2)(ii)(C) and (c)(2)(ii)(H)(1);
    e. In paragraph (c)(3)(iii) by revising the first and second 
sentences;
    f. In paragraph (c)(3)(iv) by adding in the second sentence the 
word "the" 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;

[[Page 40447]]

    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;
    i. In paragraph (c)(3)(x) by adding the words ", if 
applicable," after the words "Sec. 75.20(b)(3) 
and";
    j. 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;
    k. 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).
    l. 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;
    m. In paragraph (c)(5) by adding the word "rate" after 
the words "heat input";
    n. Revising paragraphs (c)(6)(v), (c)(7)(ii), and (c)(8)(ii);
    o. Adding a new paragraph (c)(7)(iii);
    p. Revising paragraph (c)(10); and
    q. 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) *&ensp;*&ensp; *
    (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 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 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 unit or stack 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 (c)(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.
* * * * *
    (C) For flow rate monitoring systems installed on peaking units or 
bypass stacks and for flow monitors exempted from multiple-level RATA 
testing under section 6.5.2(e) of appendix A to this part, a single-
load (or single-level) RATA is required. For all other flow rate 
monitoring systems, a 2-load (or 2-level) RATA is required at the two 
most frequently-used load or operating levels (as defined under section 
6.5.2.1 of appendix A to this part), with the following exceptions. 
Except for flow monitors exempted from 3-level RATA testing under 
section 6.5.2(e) of appendix A to this part, a 3-load flow RATA is 
required at least once every five years and is also required if the 
flow monitor polynomial coefficients or K factor(s) are changed prior 
to conducting the flow RATA required under this paragraph.
* * * * *
    (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 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 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 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) For each flow monitoring system required by this subpart, 
except for flow monitors installed on non-load-based units that do not 
produce electrical or thermal output, flow-to-load ratio tests are 
required in the second and third calendar quarters, in accordance with 
section 2.2.5 of appendix B to this part. 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

[[Page 40448]]

year, if the unit or stack does not operate in the second quarter).
    (7) * * *
    (ii) The applicable missing data procedures of 
Sec. 75.31 through 75.37 shall be used, with one 
exception. When a fuel which has a significantly higher NO_X 
emission rate than any of the fuel(s) combusted in prior ozone seasons 
is combusted in the unit, and no quality-assured NO_X 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_X emission rate, as defined in 
Sec. 72.2 of this chapter, from a NO_X-diluent 
continuous emission monitoring system, or the maximum potential 
concentration of NO_X, as defined in section 2.1.2.1 of 
appendix A to this part, from a NO_X 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_X data until the first hour 
that quality-assured NO_X data are obtained while combusting 
the new fuel, and then shall resume use of the missing data routines in 
Sec. 75.31 through 75.37; and
    (iii) In order to apply the missing data routines described in 
Sec. 75.31 through 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) In Sec. 75.32(a), the phrases "the first 720 
quality-assured monitor operating hours within the ozone season" 
and "the first 2,160 quality-assured monitor operating hours 
within the ozone season" apply, respectively, instead of the 
phrases "the first 720 quality-assured monitor operating 
hours" and "the first 2,160 quality-assured monitor 
operating hours".
    (D) In Sec. 75.32(a)(1), the phrase "Following 
initial certification, prior to completion of 3,672 unit (or stack) 
operating hours within the ozone season" applies instead of the 
phrase "Prior to completion of 8,760 unit (or stack) operating 
hours following initial certification".
    (E) In Equation 8, the phrase "Total unit operating hours 
within the ozone season" applies instead of the phrase 
"Total unit operating hours".
    (F) In Sec. 75.32(a)(2), the phrase "3,672 unit (or 
stack) operating hours within the ozone season" applies instead 
of the phrase "8,760 unit (or stack) operating hours".
    (G) 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".
    (H) 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 or stack 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 years (26,280 
clock hours) earlier shall be used in Equation 9. For a unit that has 
accumulated fewer than 3,672 ozone season operating hours in the 
previous three years, use the following: in the numerator of Equation 9 
use "Total unit operating hours within the ozone season for which 
quality-assured data were recorded in the previous three years"; 
and in the denominator of Equation 9 use "Total unit operating 
hours within the ozone season, in the previous three years'."
    (I) In Sec. 75.33(a), the phrases "the first 720 
quality-assured monitor operating hours within the ozone season" 
and "the first 2,160 quality-assured monitor operating hours 
within the ozone season" apply, respectively, instead of the 
phrases "the first 720 quality-assured monitor operating 
hours" and "the first 2,160 quality-assured monitor 
operating hours".
    (J) 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 use only quality-assured monitor operating 
hours of data that were recorded within the ozone season and no more 
than three years (26,280 clock hours) prior to the date and time of the 
missing data period."
    (K) In Sec. 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".
    (L) In Sec. 75.34(a)(3), the phrase "720 quality-
assured monitor operating hours within the ozone season" applies 
instead of "720 quality-assured monitor operating hours".
    (8) * * *
    (ii) For units with add-on emission controls, using the missing 
data options in Sec. 75.34(a)(1) through 
Sec. 75.34(a)(4), 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).
* * * * *
    (10) Units may qualify to use the low mass emissions excepted 
monitoring methodology in Sec. 75.19 on an ozone season basis. 
In order to be allowed to use this methodology, a unit may not emit 
more than 50 tons of NO_X per ozone season, as provided in 
Sec. 75.19(a)(1)(i)(A)(3). If any low mass emissions unit fails 
to provide a demonstration that its ozone season NO_X mass 
emissions are less than or equal to 50 tons, then the unit is 
disqualified from using the methodology. The owner or operator must 
install and certify any equipment needed to ensure that the unit is 
monitored using an acceptable methodology by December 31 of the 
following year.
* * * * *

Appendix A Section 1[Amended]

    47. Appendix A to part 75 is amended by:
    a. In section heading 1.1 by revising the words "Pollutant 
Concentration and CO₂ or O₂" to read 
"Gas";
    b. In the second sentence of section 1.1 by revising the words 
"SO₂ pollutant concentration monitor or 
NO_X" to read "SO₂, CO₂, 
O₂, or NO_X concentration monitoring system or 
NO_X-diluent";
    c. In section heading 1.1.1 by removing the words "Pollutant 
Concentration and CO₂ or O₂";
    d. In section heading 1.1.2 by removing the words "Pollutant 
Concentration and CO₂ or O₂ 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.

[[Page 40449]]

    48. 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. Amending paragraph (a) of section 2.1.1.1 by adding two new 
sentences following the third sentence;
    d. Transferring 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, and 
then revising the definition of the variable "%S" in 
Equation A-1b and adding a definition for the variable 
"GCV" after the definition of the variable 
"%CO_2w" in Equation A-1b;
    e. Amending paragraph (b) of section 2.1.1.1 by adding a new 
sentence after the first sentence and by adding two new sentences to 
the end of the paragraph;
    f. Adding three sentences to the end of paragraph (a) of section 
2.1.1.2;
    g. Adding a new second sentence to paragraph (c) of section 2.1.1.2 
;
    h. Revising the definition of the variable "MPC" in 
Equation A-2 of paragraph (c) of section 2.1.1.2;
    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 new second 
sentence;
    k. Removing the first sentence of paragraph (d) of section 2.1.1.4 
and adding three sentences in its place;
    l. Adding a new fifth sentence in paragraph (g) of section 2.1.1.4;
    m. In the first sentence of section 2.1.1.5, revising the words 
"paragraphs (a) and (b)" to read "paragraphs (a), 
(b), and (c)";
    n. Removing the final sentence in paragraph (c) of section 2.1.1.5 
and adding a new final sentence;
    o. In section 2.1.2, revising the words "section 
2.1.2.1" to read "sections 2.1.2.1 through 2.1.2.5 of this 
appendix";
    p. In paragraph (a) of section 2.1.2.1 by adding a new second 
sentence, by revising the word "part" to read 
"section" in the first sentence of Option 1, by adding two 
new sentences at the end of Option 1, by adding a new sentence at the 
end of Option 2, by removing the word "or" from Option 3, 
by removing the period at the end of Option 4 and adding "; 
or" in its place; and by adding a new Option 5;
    q. Adding a new final sentence to paragraph (b) of section 2.1.2.1;
    r. Adding two new sentences to the end of paragraph (c) of section 
2.1.2.1;
    s. Revising the first sentence of paragraph (d) of section 2.1.2.1;
    t. Revising paragraph (e) and Table 2-2 in section 2.1.2.1;
    u. Revising paragraph (a) of section 2.1.2.2;
    v. In the third sentence of paragraph (b) of section 2.1.2.2, 
adding the words "(if applicable)" after the words " 
NO_X emissions";
    w. In paragraph (c) of section 2.1.2.2 by adding the words 
"from the NO_X component of a certified monitoring 
system," after the words "quality assured data" in 
the first sentence, by adding the words "(for units with add-on 
NO_X controls or turbines using dry low NO_X 
technology)" after the words "malfunction or" in the 
second sentence, by adding the words "(if applicable)" 
after the words "NO_X emissions" in the third 
sentence, and by adding a new second sentence after the first sentence;
    x. Revising the fourth sentence of paragraph (a) of section 
2.1.2.3;
    y. In the first sentence of paragraph (b) of section 2.1.2.3, 
revising the words "requires a span" to read 
"requires or allows the use of a span value";
    z. Revising the second sentence of paragraph (b) of section 2.1.2.4 
and adding a new sentence after the first sentence;
    aa. Removing the first sentence of paragraph (c) of section 2.1.2.4 
and adding three sentences in its place;
    bb. In paragraph (e) of section 2.1.2.4 by adding the words 
"or, for units that use dry low NO_X technology," 
after the word "SNCR),";
    cc. Adding a new sentence after the fourth sentence in paragraph 
(f) of section 2.1.2.4;
    dd. In the third sentence of section 2.1.2.5, revising the words 
"paragraphs (a) and (b)" to read "paragraphs (a), 
(b), and (c)";
    ee. In paragraph (c) of section 2.1.2.5, adding the word 
"diagnostic" before the words "linearity test" 
in the fifth sentence and revising the final sentence;
    ff. Adding a sentence to the end of the section 2.1.3;
    gg. Adding two new sentences to the beginning of section 2.1.3.3;
    hh. Revising the third sentence of section 2.1.4.1;
    ii. 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";
    jj. Adding a sentence to the end of section 2.1.6; and
    kk. Adding text to reserved section 2.2.
    The revisions and additions read as follows:

Appendix A to Part 75 Specifications and Test Procedures

* * * * *

2. Equipment Specifications

2.1Instrument 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) SO₂ readings obtained during the 
combustion of very low sulfur fuel (as defined in Sec. 72.2 
of this chapter); (2) SO₂ or NO_X readings 
recorded on the high measurement range, for units with 
SO₂ or NO_X emission controls and two span 
values, unless the emission controls are operated seasonally (for 
example, only during the ozone season); or (3) SO₂ or 
NO_X 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 
SO₂), or according to sections 2.1.2.2, 2.1.2.4(a) and 
(f) of this appendix (for NO_X).

2.1.1SO₂ Pollutant Concentration Monitors

2.1.1.1Maximum Potential Concentration

    (a) * * * If both the fuel sulfur content and the GCV 
are routinely determined from each fuel sample, the owner or 
operator may, as an alternative to using the highest individual 
percent sulfur and lowest individual GCV values in the MPC 
calculation, pair the sulfur content and GCV values from each sample 
analysis and calculate the ratio of percent sulfur to GCV (i.e., %S/
GCV) for each pair of values. If this option is selected, the MPC 
shall be calculated using the highest %S/GCV ratio in Equation 
A-1a or A-1b.
* * * * *
(Eq. A-1b)
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) * * * For the purposes of this section, 2.1.1.1, a 
"certified" CEMS means a CEM system that has met the 
applicable certification requirements of either: This part, or part 
60 of this chapter, or a State CEM program, or the source operating 
permit. * * * 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

[[Page 40450]]

MPC shall be adjusted in accordance with section 2.1.1.5, and 
corresponding span and range adjustments shall be made, if 
necessary.
* * * * *

2.1.1.2Maximum 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.
* * * * *
    (c) * * * For the purposes of this section, 2.1.1.2, a 
"certified" CEMS means a CEM system that has met the 
applicable certification requirements of either: This part, or part 
60 of this chapter, or a State CEM program, or the source operating 
permit.
* * * * *
MPC = Maximum potential concentration (ppm), as determined by Eq. 
A-1a or A-1b in section 2.1.1.1 of this appendix.
* * * * *

2.1.1.3Span Value(s) and Range(s)

    * * * If the SO₂ span concentration is &le; 
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 SO₂ 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. * * *

2.1.1.4Dual Span and Range Requirements

* * * * *
    (c) * * * Alternatively, if RATAs are performed and 
passed on both measurement ranges, the owner or operator may use two 
separate SO₂ 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 SO₂ 
components of a single, primary SO₂ monitoring system; 
designate the low and high monitor ranges as the SO₂ 
components of two separate, primary SO₂ 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 SO₂ 
analyzer is used, designate the low and high ranges as a single 
SO₂ component of a primary SO₂ 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 
SO₂ analyzers are connected to separate probes and sample 
interfaces, designate the analyzers as the SO₂ components 
of two separate, primary SO₂ monitoring systems. For 
units with SO₂ controls, if the default high range value 
is used, designate the low range analyzer as the SO₂ 
component of a primary SO₂ monitoring system. 
* * *
* * * * *
    (g) * * * However, if the default high range option in 
paragraph (f) of this section is selected, the full-scale of the low 
measurement range shall not exceed five times the MEC value (where 
the MEC is rounded upward to the next highest multiple of 10 ppm). 
* * *

2.1.1.5Adjustment 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.

2.1.2NO_X Pollutant Concentration Monitors

* * * * *

2.1.2.1Maximum Potential Concentration

    (a) * * * For the purposes of this section, 2.1.2.1, 
and section 2.1.2.2 of this appendix, a "blend" means a 
frequently-used fuel mixture having a consistent composition (e.g., 
an oil and gas mixture where the relative proportions of the two 
fuels vary by no more than 10%, on average). * * *
    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 2: * * * For a new gas-fired or oil-fired 
combustion turbine, if a default MPC value of 50 ppm was previously 
selected from Table 2-2, that value may be used until March 
31, 2003;
* * * * *
    Option 5: If a reliable estimate of the uncontrolled 
NO_X emissions from the unit is available from the 
manufacturer, the estimated value may be used.
    (b) * * * As a second alternative, when the 
NO_X MPC is determined from emission test results or from 
historical CEM data, as described in paragraphs (a), (d) and (e) of 
this section, quality-assured diluent gas (i.e., O₂ or 
CO₂) data recorded concurrently with the MPC may be used 
to calculate the MER.
    (c) * * * Note that whichever MPC option in paragraph 
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_X controls (whether or 
not the unit is equipped with low-NO_X burner technology), 
or for units equipped with dry low-NO_X (DLN) technology, 
NO_X 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 are not 
in operation or when the DLN controls are not in the premixed (low-
NO_X) mode. * * *
    (e) If historical CEM data are used to determine the MPC, the 
data must, for uncontrolled units or units equipped with low-
NO_X burner technology and no other NO_X 
controls, represent a minimum of 720 quality assured monitor 
operating hours from the NO_X component of a certified 
monitoring system, obtained under various operating conditions 
including the minimum safe and stable load, normal load (including 
periods of high excess air at normal load), and maximum load. For 
the purposes of this section, 2.1.2.1, a "certified" 
CEMS means a CEM system that has met the applicable certification 
requirements of either: this part, or part 60 of this chapter, or a 
State CEM program, or the source operating permit. For a unit with 
add-on NO_X controls (whether or not the unit is equipped 
with low-NO_X burner technology), or for a unit equipped 
with dry low-NO_X (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 are not in operation or when the DLN controls are 
not in the premixed (low-NO_X mode). For units that do not 
produce electrical or thermal output, the data must represent the 
full range of normal process operation. The highest hourly 
NO_X concentration in ppm shall be the MPC.
* * * * *

[[Page 40451]]

[GRAPHIC]
[TIFF OMITTED]
TR12JN02.008

2.1.2.2Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of NO_X during normal operation for 
affected units with add-on NO_X controls of any kind 
(e.g., steam injection, water injection, SCR, or SNCR) and for 
turbines that use dry low-NO_X technology. 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. Calculate the MEC of NO_X 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_X 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_X 
controls or uses dry low NO_X technology, and has a 
federally-enforceable permit limit for NO_X 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) * * * For the purposes of this section, 2.1.2.2, a 
"certified" CEMS means a CEM system that has met the 
applicable certification requirements of either: this part, or part 
60 of this chapter, or a State CEM program, or the source operating 
permit. * * *

2.1.2.3 Span Value(s) and Range(s)

    (a) * * * If the NO_X span concentration is 
&le;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. * * *
* * * * *

2.1.2.4Dual Span and Range Requirements

* * * * *
    (b) * * * Two separate NO_X analyzers 
connected to separate probes and sample interfaces may be used if 
RATAs are passed on both ranges. For units with add-on 
NO_X emission controls (e.g., steam injection, water 
injection, SCR, or SNCR) or units equipped with dry low-
NO_X technology, the owner or operator may use a low range 
analyzer and a "default high range value," as described 
in paragraph 2.1.2.4(e) of this section, 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_X 
components of a single, primary NO_X monitoring system; 
designate the low and high ranges as the NO_X components 
of two separate, primary NO_X 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_X analyzer is used, designate the 
low and high ranges as a single NO_X component of a 
primary NO_X 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_X analyzers 
are connected to separate probes and sample interfaces, designate 
the analyzers as the NO_X components of two separate, 
primary NO_X monitoring systems. For units with add-on 
NO_X controls or units equipped with dry low-
NO_X technology, if the default high range value is used, 
designate the low range analyzer as the NO_X component of 
the primary NO_X monitoring system. * * *
* * * * *
    (f) * * * However, if the default high range option in 
paragraph (e) of this section is selected, the full-scale of the low 
measurement range shall not exceed five times the MEC value (where 
the MEC is rounded upward to the next highest multiple of 10 ppm). 
* * *

2.1.2.5Adjustment 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 CO₂ and O₂ 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).
* * * * *

2.1.3.3Adjustment of Span and Range

    The MPC and MEC values for diluent monitors are subject to the 
same periodic review as SO₂ and NO_X 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. * * *
* * * * *

2.1.4Flow Monitors

* * * * *

2.1.4.1Maximum Potential Velocity and Flow Rate

    * * * If using test values, use the highest average 
velocity (determined from the Method 2 traverses) measured at or 
near the maximum unit operating load (or, for units that do not 
produce electrical or thermal output, at the normal process 
operating conditions corresponding to the maximum stack gas flow 
rate). * * *
* * * * *

[[Page 40452]]

2.1.6Maximum Potential Moisture Percentage

    * * * Alternatively, a default maximum potential 
moisture value of 15.0 percent H₂O may be used.

2.2Design for Quality Control Testing

2.2.1Pollutant Concentration and CO₂ or O₂ 
Monitors

    (a) Design and equip each pollutant concentration and 
CO₂ or O₂ 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 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 
CO₂ or O₂ 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.

2.2.2Flow Monitors

    Design all flow monitors to meet the applicable performance 
specifications.

2.2.2.1Calibration Error Test

    Design and equip each flow monitor to allow for a daily 
calibration error test consisting of at least two reference values: 
Zero to 20 percent of span or an equivalent reference value (e.g., 
pressure pulse or electronic signal) and 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 the entire flow monitoring system, from and including the 
probe tip (or equivalent) through and including the data acquisition 
and handling system, or the flow monitoring system from and 
including the transducer through and including the data acquisition 
and handling system.

2.2.2.2Interference 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 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 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. Appendix A to part 75 is amended by:
    a. Revising section heading and text of section 3.3.1;
    b. Revising paragraph (b) of section 3.3.2;
    c. In section heading 3.3.3 by removing the words "Pollutant 
Concentration";
    d. Revising the second sentence of section 3.3.3;
    e. Revising the section heading and text of section 3.3.4;
    f. Revising the second sentence of section 3.3.6; and
    g. Revising paragraph (b) of section 3.3.7.
    The revisions and additions read as follows:

3. Performance Specifications

* * * * *

3.3Relative Accuracy

3.3.1Relative Accuracy for SO₂ Monitors

    (a) The relative accuracy for SO₂ pollutant 
concentration monitors shall not exceed 10.0 percent except as 
provided in this section.
    (b) For affected units where the average of the reference method 
measurements of SO₂ concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the 
difference between the mean value of the monitor measurements and 
the reference method mean value shall not exceed &plusmn;15.0 ppm, 
wherever the relative accuracy specification of 10.0 percent is not 
achieved.

3.3.2Relative Accuracy for NO_X-Diluent Continuous 
Emission Monitoring Systems

* * * * *
    (b) For affected units where the average of the reference method 
measurements of NO_X emission rate during the relative 
accuracy test audit is less than or equal to 0.200 lb/mmBtu, the 
difference between the mean value of the continuous emission 
monitoring system measurements and the reference method mean value 
shall not exceed &plusmn;0.020 lb/mmBtu, wherever the relative 
accuracy specification of 10.0 percent is not achieved.

3.3.3Relative Accuracy for CO₂ and O₂ 
Monitors

    * * * The relative accuracy test results are also 
acceptable if the difference between the mean value of the 
CO₂ or O₂ monitor measurements and the 
corresponding reference method measurement mean value, calculated 
using equation A-7 of this appendix, does not exceed &plusmn; 
1.0 percent CO₂ or O₂.

3.3.4Relative Accuracy for Flow Monitors

    (a) The relative accuracy of flow monitors shall not exceed 10.0 
percent at any load (or operating) level at which a RATA is 
performed (i.e., the low, mid, or high 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 (or 
operating) level of the relative accuracy test audit is less than or 
equal to 10.0 fps, the difference between the mean value of the flow 
monitor velocity measurements and the reference method mean value in 
fps at that level shall not exceed &plusmn; 2.0 fps, wherever the 
10.0 percent relative accuracy specification is not achieved.
* * * * *

3.3.6Relative Accuracy for Moisture Monitoring Systems

    * * * The relative accuracy test results are also 
acceptable if the difference between the mean value of the reference 
method measurements (in percent H₂O) and the 
corresponding mean value of the moisture monitoring system 
measurements (in percent H₂O), calculated using Equation 
A-7 of this appendix does not exceed &plusmn; 1.5 percent 
H₂O.

3.3.7Relative Accuracy for NO_X Concentration 
Monitoring Systems

* * * * *
    (b) The relative accuracy for NO_X concentration 
monitoring systems shall not exceed 10.0 percent. Alternatively, for 
affected units where the average of the reference method 
measurements of NO_X concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the 
difference between the mean value of the continuous emission 
monitoring system measurements and the reference method mean value 
shall not exceed &plusmn; 15.0 ppm, wherever the 10.0 percent 
relative accuracy specification is not achieved.
* * * * *

Appendix A to Part 75[Amended]

    50. Appendix A to part 75 is amended by:
    a. In the first paragraph of section 4, by adding a new second 
sentence; and
    b. In paragraph (3) of section 4, adding the words "the 
appropriate" before the word "units", removing the 
words "of the standard", and 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 
SO₂ pollutant concentration monitor, a flow monitor, a 
CO₂ monitor, a NO_X pollutant concentration 
monitor, and a NO_X-diluent continuous emission monitoring 
system to produce a continuous readout of pollutant emission rates 
or pollutant mass emissions

[[Page 40453]]

(as applicable) in the appropriate units (e.g., lb/hr, lb/mmBtu, 
tons/hr).

* * * * *

Appendix A to Part 75[Amended]

    51. 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 adding a new first sentence, by revising the 
word "Measure" in the new second sentence to read "In 
all other cases, measure", and by removing the word 
"extended" in the new third 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 section 6.3.2 by adding a new first sentence, by revising the 
word "Perform" in the new second sentence to read "In 
all other cases, perform", and by removing the word 
"extended" before the words "unit outages" in 
the new fifth 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. Adding a new section 6.3.3;
    g. In the first sentence of paragraph (a) of section 6.4 by adding 
the word "conditional" before the words "data 
validation procedures";
    h. 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 SO₂-diluent continuous 
emission monitoring system";
    i. Revising paragraphs (a) and (c) of section 6.5;
    j. In paragraph (b) of section 6.5 by adding the words "(or 
operating)" after the word "load";
    k. In the first sentence of paragraph (f)(1) of section 6.5 by 
adding the word "conditional" before the words "data 
validation procedures";
    l. In the second sentence of paragraph (g) of section 6.5 by 
removing the words "SO₂-diluent";
    m. Revising paragraph (a) of section 6.5.1 and paragraph (a) of 
section 6.5.2;
    n. 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)";
    o. In paragraph (c) of section 6.5.2 by adding the words "(or 
three operating levels)" after the word "level(s)", 
and by adding the words "or (e)" after the words 
"paragraph (b)";
    p. In paragraph (d) of section 6.5.2 by adding the words "(or 
operating levels)" after the word "level(s)";
    q. Adding a new paragraph (e) to section 6.5.2;
    r. In section heading 6.5.2.1 by adding the words "(or 
Operating)" after the words "Normal Load";
    s. Revising paragraph (a) of section 6.5.2.1;
    t-v. 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 " &gt;30.0 percent, but &le;60.0 percent" and revising 
the words "60.0 to 100.0 percent" to read " &gt;60.0 
percent";
    w. Revising paragraphs (c) and (d) of section 6.5.2.1;
    x. Revising the first sentence of paragraph (e) of section 6.5.2.1;
    y. Revising section 6.5.2.2 section heading and text;
    z. Removing and reserving section 6.5.3;
    aa. In section 6.5.6 by removing the third sentence;
    bb. In paragraph (b)(2) of section 6.5.6 by revising the number 
"1.0" to read "1.2";
    cc. Adding paragraph (b)(5) to section 6.5.6;
    dd. 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)";
    ee. In paragraph (c) of section 6.5.6.3 by removing the words 
"Sec. 75.56(a)(7) or" and the words ", as 
applicable";
    ff. In paragraph (a) of section 6.5.7 by removing the words 
"or SO₂-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
    gg. In section 6.5.10 by adding a comma after the number 
"7D", and by adding a new sentence to the end of the 
paragraph.
    The revisions and additions read as follows:

6. Certification Tests and Procedures

* * * * *

6.37-Day Calibration Error Test

6.3.1Gas Monitor 7-day Calibration Error Test

    The following monitors and ranges are exempted from the 7-day 
calibration error test requirements of this part: The 
SO₂, NO_X, CO₂ and O₂ 
monitors installed on peaking units (as defined in Sec. 72.2 
of this chapter); and any SO₂ or NO_X 
measurement range with a span value of 50 ppm or less. 
* * *
* * * * *

6.3.2Flow Monitor 7-day Calibration Error Test

    Flow monitors installed on peaking units (as defined in 
Sec. 72.2 of this chapter) are exempted from the 7-day 
calibration error test requirements of this part. * * *
* * * * *
    6.3.3For gas or flow monitors installed on peaking units, 
the exemption from performing the 7-day calibration error test 
applies as long as the unit continues to meet the definition of a 
peaking unit in Sec. 72.2 of this chapter. However, if at 
the end of a particular calendar year or ozone season, it is 
determined that peaking unit status has been lost, the owner or 
operator shall perform a diagnostic 7-day calibration error test of 
each monitor installed on the unit, by no later than December 31 of 
the following calendar year.
* * * * *

6.5Relative 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 SO₂ or NO_X 
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.
* * * * *

6.5.1Gas Monitoring System RATAs (Special Considerations)

    (a) Perform the required relative accuracy test audits for each 
SO₂ or CO₂ pollutant concentration monitor, 
each CO₂ or O₂ diluent monitor used to 
determine heat input, each NO_X-diluent continuous 
emission monitoring system, and each NO_X concentration 
monitoring system used to determine NO_X 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

[[Page 40454]]

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.
* * * * *

6.5.2Flow Monitor RATAs (Special Considerations)

    (a) Except as otherwise provided in paragraph (b) or (e) of this 
section, 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.
* * * * *
    (e) For flow monitors installed on units that do not produce 
electrical or thermal output, the flow RATAs for initial 
certification or recertification may be done at fewer than three 
operating levels, if:
    (1) The owner or operator provides a technical justification in 
the hardcopy portion of the monitoring plan for the unit required 
under Sec. 75.53(e)(2), demonstrating that the unit operates 
at only one level or two levels during normal operation (excluding 
unit startup and shutdown). Appropriate documentation and data must 
be provided to support the claim of single-level or two-level 
operation; and
    (2) The justification provided in paragraph (e)(1) of this 
section is deemed to be acceptable by the permitting authority.
    6.5.2.1Range of Operation and Normal Load (or Operating) 
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 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 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 of thousands of lb/hr of steam load; or
    (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" with the 
word "minimum" in the definitions of "MPV," 
"H_f," "% O_2d," and 
"% H₂O," and replace the word 
"minimum" with the word "maximum" in the 
definition of "CO_2d." Alternatively, 0.0 ft/
sec may be used as the lower boundary of the range of operation.
* * * * *
    (c) Units that do not produce electrical or thermal output are 
exempted from the requirements of this paragraph, (c). 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.
    (d) Determination of normal load (or operating level)
    (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, 
the normal operating level(s) shall be determined using sound 
engineering judgment, based on knowledge of the unit and operating 
experience with the industrial process.
    (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. 
* * *

6.5.2.2Multi-Load (or Multi-Level) Flow RATA Results

    For each multi-load (or multi-level) flow RATA, calculate the 
flow monitor relative accuracy at each operating level. If a flow 
monitor relative accuracy test is failed or aborted due to a problem 
with the monitor on any level of a 2-level (or 3-level) relative 
accuracy test audit, the RATA must be repeated at that load (or 
operating) level. However, the entire 2-level (or 3-level) relative 
accuracy test audit does not have to be repeated unless the flow 
monitor polynomial coefficients or K-factor(s) are changed, in which 
case a 3-level RATA is required (or, a 2-level RATA, for units 
demonstrated to operate at only two levels, under section 6.5.2(e) 
of this appendix).

6.5.3[Reserved]

* * * * *

6.5.6Reference Method Traverse Point Selection

* * * * *
    (b) * * *
    (5) If Method 7E is used as the reference method for the RATA of 
a NO_X 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.
* * * * *

[[Page 40455]]

6.5.7Sampling 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 
flow 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. 
* * *
* * * * *

6.5.10Reference Methods

    * * * Notwithstanding these requirements, Method 20 
may be used as the reference method for relative accuracy test 
audits of NO_X monitoring systems installed on combustion 
turbines.

Appendix A to part 75[Amended]

    52. Appendix A to part 75 is amended by:
    a. In section heading 7.3 by revising the words 
"SO₂-Diluent Continuous Emission" to read 
"O₂ Monitors, NO_X Concentration";
    b. Revising the first sentence of section 7.3;
    c. Revising the variable
    [GRAPHIC]
[TIFF OMITTED]
TR12JN02.009
    
in the list of defined variables for Eq. A-7 to read
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.010

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_X" to read "NO_X-
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_X" after both occurrences of the word 
"SO₂" and, in the last sentence, by revising the 
word" NO_X" to read "NO_X-
diluent";
    g. Adding a new paragraph (g) to section 7.6.5;
    h. In paragraph (a) of section 7.7 by removing the fourth sentence;
    i. Revising paragraph (b) of section 7.7;
    j. In the variable "(Heat Input)_avg" under 
Eq. A-13a in paragraph (c) of section 7.7 by adding a second and 
third sentence to the definition;
    k. 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;
    l. In section 7.8 by designating the existing text as paragraph 
(a), removing 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
    m. Revising Figure 6.
    The revisions and additions read as follows:

7. Calculations

* * * * *

7.3Relative Accuracy for SO₂ and CO₂ 
Pollutant Concentration Monitors, O₂ Monitors, 
NO_X Concentration Monitoring Systems, and Flow Monitors

    Analyze the relative accuracy test audit data from the reference 
method tests for SO₂ and CO₂ pollutant 
concentration monitors, O₂ monitors used only for heat 
input rate determination, NO_X concentration monitoring 
systems used to determine NO_X mass emissions under 
subpart H of this part, and flow monitors using the following 
procedures.* * *
* * * * *

7.6Bias Test and Adjustment Factor

* * * * *
7.6.5Bias Adjustment
* * * * *
    (g) For units that do not produce electrical or thermal output, the 
provisions of paragraphs (a) through (f) of this section apply, except 
that the terms, "single-load", "2-load", 
"3-load", and "load level" shall be replaced, 
respectively, with the terms, "single-level", "2-
level", "3-level", and "operating level".

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

* * * * *
    (b) In Equation A-13, for a common stack, determine 
L_avg 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_ref for the unit or a separate value of Q_ref for 
each stack. In the former case, calculate Q_ref 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_ref 
for each stack by taking the arithmetic average, for all RATA runs, of 
the flow rates through the stack. For a unit with a multiple stack 
discharge configuration consisting of a main stack and a bypass stack 
(e.g., a unit with a wet SO₂ scrubber), determine 
Q_ref separately for each stack at the time of the normal 
load flow RATA. Round off the value of R_ref to two decimal 
places.
    (c) * * *
Where:

    * * *
(Heat Input)_avg=* * * 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.
* * * * *

7.8Flow-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.
* * * * *

[[Page 40456]]

[GRAPHIC]
[TIFF OMITTED]
TR12JN02.011

* * * * *

    53. Appendix B to part 75 is amended by:
    a. Adding a fourth sentence to section 1;
    b. Removing the word "and" before the words 
"section 2.1.5.1" in the second sentence of section 1.3.1; 
and

[[Page 40457]]

    c. Removing the words "unit manufacturer's" in the 
first sentence of section 1.3.6.
    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.

* * * * *

Appendix B to Part 75[Amended]

    54. Appendix B to Part 75 is amended by:
    a. In paragraph (a) of section 2.1.4 by removing the words 
"(or exceeds 10 ppm, for span values &lt;200 ppm)" in the 
first sentence, by adding the words "of appendix A to this 
part" after "Equation A-6" in the second 
sentence, and by adding a new third sentence after the second sentence;
    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 section 2.2.2, by revising the words "section 
2.2.3(f)" to read "section 2.2.3(g)";
    d. In paragraph (c) of section 2.2.3 by adding a third sentence;
    e. In the second sentence of paragraph (e) of section 2.2.3 by 
removing the words "or SO₂-diluent";
    f. In paragraph (b) of section 2.2.4 by adding the words 
"first unit operating" before the words "hour 
following" in the first sentence;
    g. 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;
    h. Revising the third sentence of paragraph (a)(1) of section 
2.2.5;
    i. In paragraph (a)(3) of section 2.2.5 by adding the word 
"rate" after the words "heat input";
    j. 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 &plusmn; 10 percent of 
L_avg)" after the word "rates";
    k. Adding a sentence at the end of paragraph (b)(4) of section 
2.2.5;
    l. Revising the introductory text of paragraph (c) of section 
2.2.5;
    m. In paragraph (c)(1) of section 2.2.5 by removing the semicolon 
and adding in its place a period after the word "sub-
bituminous)" and by adding a new third sentence;
    n. In paragraph (c)(8) of section 2.2.5 by removing the second 
sentence and adding two new sentences in its place;
    o. 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";
    p. Revising paragraph (b) of section 2.2.5.1;
    q. Revising section 2.2.5.2;
    r. In paragraph (a) of section 2.2.5.3 by adding the words 
"either the hour in which the abbreviated flow-to-load test is 
passed, or" after the word "until" in the second 
sentence, and by revising the word "The" at the beginning 
of the third sentence to read "If the latter option is selected, 
the";
    s. In the second sentence of paragraph (b) of section 2.2.5.3 by 
revising the number "5.0" to read "10.0";
    t. 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;
    u. Removing and reserving paragraphs (b) and (g) of section 
2.3.1.2;
    v. 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;
    w. 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 " &lt; 10.0 fps" and by removing the words 
"(10.0 percent if prior to January 1, 2000)";
    x. 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";
    y. 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_X emission rate";
    z. In section heading 2.3.1.3 by adding the words "(or 
Operating)" after the words "RATA Load";
    aa. 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)";
    bb. Revising paragraphs (b) and (c) of section 2.3.1.3;
    cc. In paragraph (c) of section 2.3.2 by adding a new third 
sentence;
    dd. In paragraph (d) of section 2.3.2 by adding the words 
"(or single level)" after the word "single-
load" and adding the words "(or multiple level)" 
after the word "multiple-load", and in paragraphs (d) and 
(f) of section 2.3.2 by adding the words "(or operating 
levels(s))" after the words "load level(s)", the 
words "(or 3-level)" after the words "3-load", 
and the words ", except as otherwise provided in section 
2.3.1.3(c)(5) of this appendix" immediately before the period at 
the end of each paragraph;
    ee. By revising paragraph (e) of section 2.3.2;
    ff. Revising paragraph (a) of section 2.3.3;
    gg. Revising paragraph (b) of section 2.4;
    hh. Revising footnote 2 of Figure 1 to Appendix B of Part 75; and
    ii. In Figure 2 to Appendix B of Part 75 by removing the entire 
entry for "Flow (Phase I)" and revising the phrase 
"Flow (Phase II)" in the first column to read 
"Flow".
    The revisions and additions read as follows:

2. Frequency of Testing

* * * * *

2.1Daily Assessments

* * * * *

2.1.4Data Validation

    (a) * * * In addition, an SO₂ or 
NO_X monitor for which the calibration error exceeds 5.0 
percent of the span value shall not be considered out-of-control if 
&bond;R-A&bond; in Equation A-6 does not exceed 5.0 ppm 
(for span values &le;50 ppm), or if &bond;R-A&bond; does not 
exceed 10.0 ppm (for span values &gt; 50 ppm, but &le; 200 ppm). 
* * *
* * * * *

2.2Quarterly Assessments

* * * * *

2.2.3Data 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.
* * * * *

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

    (a) * * * 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 
&plusmn;10.0 percent of L_avg and may calculate 
R_h values for only the remaining hours.
* * * * *
    (1) * * * For a unit that discharges its emissions 
through multiple stacks or that monitors its emissions in multiple

[[Page 40458]]

breechings, Q_h 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) * * *
    (4) * * * If E_f 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_f, after excluding all non-representative 
hourly flow rates, as provided in paragraph (c) of this section.
    (c) Recalculation of E_f. If the owner or operator did 
not exclude any hours within &plusmn;10 percent of L_avg 
from the original data analysis and chooses to recalculate 
E_f, 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_f 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_f 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_f exceeded the applicable limit. * * *

2.2.5.1Option 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_f 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_f 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.

2.2.5.2Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of appendix A to this part) of each flow monitor for 
which E_f 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_f 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_f 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, except as otherwise specified 
in section 2.3.1.3 of this appendix.
* * * * *

2.3Semiannual and Annual Assessments

* * * * *

2.3.1Relative Accuracy Test Audit (RATA)

* * * * *

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

* * * * *
    (b) For flow monitors installed on peaking units and bypass 
stacks, and for flow monitors that qualify to perform only single-
level RATAs under section 6.5.2(e) of appendix A to this part, all 
required semiannual or annual relative accuracy test audits shall be 
single-load (or single-level) audits at the normal load (or 
operating level), as defined in section 6.5.2.1(d) of appendix A to 
this part.
    (c) For all other flow monitors, the RATAs shall be performed as 
follows:
    (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, or 
(if applicable) at the operating levels determined under section 
6.5.2(e) 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 &ge; 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 &fnl;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, except for flow monitors that 
are exempted from 3-load (or 3-level) RATA testing under section 
6.5.2(b) or 6.5.2(e) of appendix A to this part.
    (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 that are exempted 
from 3-load (or 3-level) RATA testing under section 6.5.2(b) or 
6.5.2(e) of appendix A to this part. For monitors so exempted under 
section 6.5.2(b), a single-load flow RATA is required. For monitors 
so exempted under section 6.5.2(e), either a single-level RATA or a 
2-level RATA is required, depending on the number of operating 
levels documented in the monitoring plan for the unit.
    (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.
* * * * *

2.3.2Data 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

[[Page 40459]]

this part. If the option in paragraph (b)(3) of this section to use 
the data validation procedures and associated timelines in 
Sec. 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.
* * * * *

2.3.3RATA Grace Period

    (a) The owner or operator has a grace period of 720 consecutive 
unit operating hours, as defined in Sec. 72.2 of this 
chapter (or, for CEMS installed on common stacks or bypass stacks, 
720 consecutive stack operating hours, as defined in 
Sec. 72.2 of this chapter), in which to complete the 
required RATA for a particular CEMS whenever:
    (1) A required RATA has not been performed by the end of the QA 
operating quarter in which it is due; or
    (2) Five consecutive calendar years have elapsed without a 
required 3-load flow RATA having been conducted; or
    (3) For a unit which is conditionally exempted under 
Sec. 75.21(a)(7) from the SO₂ RATA requirements 
of this part, an SO₂ RATA has not been completed by the 
end of the calendar quarter in which the annual usage of fuel(s) 
with a sulfur content higher than very low sulfur fuel (as defined 
in Sec. 72.2 of this chapter) exceeds 480 hours; or
    (4) Eight successive calendar quarters have elapsed, following 
the quarter in which a RATA was last performed, without a subsequent 
RATA having been done, due either to infrequent operation of the 
unit(s) or frequent combustion of very low sulfur fuel, as defined 
in Sec. 72.2 of this chapter (SO₂ monitors, 
only), or a combination of these factors.
* * * * *

2.4Recertification, 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 (or single-level) 
flow RATA is specifically required under section 2.3.1.3(b) of this 
appendix 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 &ge; 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, bypass 
stacks, or units that qualify for single-level RATA testing under 
section 6.5.2(e) of this appendix, conduct all RATAs at a single, 
normal load (or operating level). For other flow monitors, conduct 
annual RATAs at two load levels (or operating levels). Alternating 
single-load and 2-load (or single-level and 2-level) RATAs may be 
done if a monitor is on a semiannual frequency. A single-load (or 
single-level) RATA may be done in lieu of a 2-load (or 2-level) RATA 
if, since the last annual flow RATA, the unit has operated at one 
load level (or operating level) for &ge; 85.0 percent of the time. A 
3-level RATA is required at least once every five calendar years and 
whenever a flow monitor is re-linearized, except for flow monitors 
exempted from 3-level RATA testing under section 6.5.2(b) or 
6.5.2(e) of appendix A to this part.

* * * * *

    55. Appendix C to part 75 is amended by:
    a. In the section heading of section 2 by revising the word 
"Load-Based" to read "Load-based" and by adding 
the words ", NO_X Concentration," after the words 
"Flow Rate"; and
    b. Adding a new section 3.
    The revisions and additions read as follows:

Appendix C to Part 75 Missing Data Estimation Procedures

* * * * *

3. Non-load-based Procedure for Missing Flow Rate, NO_X 
Concentration, and NO_X Emission Rate Data (Optional)

3.1Applicability

    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_X 
emission rate (in lb/mmBtu) from NO_X-diluent continuous 
emission monitoring systems, and NO_X concentration data 
(in ppm) from NO_X concentration monitoring systems used 
to determine NO_X mass emissions.

3.2Procedure

    3.2.1 For each monitored parameter (flow rate, NO_X 
emission rate, or NO_X 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_X 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_X 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.
    3.2.2In the electronic quarterly report required under 
Sec. 75.64, indicate for each hour of unit operation the 
operational bin associated with the NO_X or flow rate 
data, by recording the number assigned to the bin under section 
3.2.1 of this appendix.
    3.2.3The 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 (as 
applicable) for each unit operating hour of missing flow or 
NO_X 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 in the 
previous 3 years:
    3.2.3.1Average of the hourly flow rates reported by a flow 
monitor (scfh).
    3.2.3.2The 90th percentile value of hourly flow rates 
(scfh).
    3.2.3.3The 95th percentile value of hourly flow rates 
(scfh).
    3.2.3.4The maximum value of hourly flow rates (scfh).
    3.2.3.5Average of the hourly NO_X emission 
rates, in lb/mmBtu, reported by a NO_X-diluent continuous 
emission monitoring system.
    3.2.3.6The 90th percentile value of hourly NO_X 
emission rates (lb/mmBtu).
    3.2.3.7The 95th percentile value of hourly NO_X 
emission rates (lb/mmBtu).
    3.2.3.8The maximum value of hourly NO_X emission 
rates, in (lb/mmBtu).
    3.2.3.9Average of the hourly NO_X pollutant 
concentrations (ppm), reported by a NO_X concentration 
monitoring system used to determine NO_X mass emissions, 
as defined in Sec. 75.71(a)(2).
    3.2.3.10The 90th percentile value of hourly NO_X 
pollutant concentration (ppm).
    3.2.3.11The 95th percentile value of hourly NO_X 
pollutant concentration (ppm).
    3.2.3.12The maximum value of hourly NO_X 
pollutant concentration (ppm).
    3.2.4When a bias adjustment is necessary for the flow 
monitor and/or the NO_X-diluent continuous emission 
monitoring system (and/or the NO_X concentration 
monitoring system), apply the bias adjustment factor to all data 
values placed in the operational bins.

[[Page 40460]]

    3.2.5Calculate all CEMS data averages, maximum values, and 
percentile values determined by this procedure using bias-adjusted 
values.
    3.2.6Use the calculated monitor or monitoring system data 
averages, maximum values, and percentile values to substitute for 
missing flow rate and NO_X emission rate data (and where 
applicable, NO_X concentration data) according to the 
procedures in subpart D of this part.

Appendix D Section 1 [Amended]

    56. Appendix D to Part 75 is amended by removing the final sentence 
of section 1.2.

    57. 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 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. Revising paragraph (c) of section 2.1.6;
    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 paragraph (a) of section 2.1.6.1 by adding the word 
"upscale" after the word "other" in the second 
sentence 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_base" and 
"L_avg" 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)_avg" under Eq. D-1c;
    x. Adding a new paragraph (e) to section 2.1.7.1;
    y. In paragraph (a) of section 2.1.7.2 by adding a new third 
sentence;
    z. Revising paragraph (b) of section 2.1.7.2;
    aa. In the variable for "(Heat Input)_h" 
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";
    bb. Revising paragraph (d) of section 2.1.7.2;
    cc. Adding a third sentence to paragraph (h) of section 2.1.7.2;
    dd. Revising paragraph (a) of section 2.1.7.3;
    ee. Adding a second sentence to paragraph (b) of section 2.1.7.3;
    ff. 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)";
    gg. 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";
    hh. Revising Table D-3 in section 2.1.7.5 and Table D-4 
in section 2.2;
    ii. 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)";
    jj. Revising paragraph (b) of section 2.2.4.2;
    kk. 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" to read, respectively, the words 
"following conservative, assumed values" and "assumed 
values";
    ll. Revising paragraph (d) of section 2.2.4.3;
    mm. Revising Table D-5 in paragraph (b) of section 2.3;
    nn. In section 2.3.1.3 by adding the words "or Equation 
D-4 (if daily or hourly fuel sampling is used)" at the end 
of the first sentence;
    oo. Revising sections 2.3.1.4, 2.3.2.4, and 2.3.6;
    pp. Revising section 2.3.2.1.1 and Equation D-1h;
    qq. Removing and reserving section 2.3.2.1.2;
    rr. Revising sections 2.3.3.1.1 and 2.3.3.2;
    ss. In section 2.3.4.3 by adding a new second sentence;
    tt. In section 2.3.4.3.1 by revising the fourth sentence;
    uu. Revising section 2.3.4.3.2;
    vv. Revising paragraph (a) of section 2.3.5;
    ww. Adding section 2.3.7;
    xx. In section 2.4.1 by removing a reference to 
"2.3.3.1," in the first sentence, by removing the second 
sentence and adding two new sentences in its place, and by revising 
Table D-6;
    yy. Revising sections 2.4.2, 2.4.2.1, and 2.4.2.2; adding sections 
2.4.2.2.1 and 2.4.2.2.2; revising section 2.4.2.3; and adding sections 
2.4.2.3.1 through 2.4.2.3.4; and
    zz. In section 2.4.3 by adding a second sentence.
    The revisions and additions read as follows:

2. Procedure

2.1Fuel Flowmeter Measurements

* * * * *
    2.1.2Install 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). 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,

[[Page 40461]]

record, and report NO_X mass emissions under a State or 
federal NO_X 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. When a 
fuel flowmeter is installed in a common pipe header, proceed as 
follows:
    2.1.2.1Measure the fuel flow rate in the common pipe, and 
combine SO₂ mass emissions (Acid Rain Program units only) 
for the affected units for recordkeeping and compliance purposes; and
    2.1.2.2Apportion 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.
* * * * *
2.1.4.1Start-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. * * *
* * * * *
2.1.4.3Emergency Fuel
    The designated representative of a unit that is restricted by its 
Federal, State or local permit 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 SO₂ mass emission rate, using Equations 
D-2 through D-4 (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 SO₂ 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.
* * * * *
2.1.6Quality Assurance
* * * * *
    (c) For orifice-, nozzle-, and venturi-type flowmeters, either 
perform the required flowmeter accuracy testing using the procedures in 
section 2.1.5.2 of this appendix or perform a transmitter accuracy test 
for the initial certification and once every four fuel flowmeter QA 
operating quarters thereafter. Perform a primary element visual 
inspection for the initial certification and once every 12 calendar 
quarters thereafter, according to the procedures in sections 2.1.6.1 
through 2.1.6.4 of this appendix for periodic 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.
2.1.6.1Transmitter 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.
* * * * *
2.1.6.4Primary Element Inspection
    (a) * * *
    (1) * * * If the primary element size is changed, also 
calibrate the transmitters or transducers, consistent with the new 
primary element size;
* * * * *
2.1.7Fuel Flow-to-Load Quality Assurance Testing for Certified 
Fuel Flowmeters
* * * * *
2.1.7.1Baseline 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_avg 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_base 
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_base to the nearest tenth.
* * * * *
    (e) If a unit co-fires different fuels (e.g., oil and natural gas) 
as its normal mode of operation, the gross heat rate option in 
paragraph (c) of this section may be used to determine a value of 
(GHR)_base, as follows. Derive the baseline data during co-
fired hours. Then, use Equation D-1c to calculate 
(GHR)_base, making sure that each hourly unit heat input rate 
used to calculate (Heat Input)_avg includes the contribution 
of each type of fuel.
2.1.7.2Data 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_h.
* * * * *
    (b) For a fuel flowmeter installed on a common pipe header, Lh 
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_h will be the 
sum of the fuel flow rates from all of the pipes. Round off each value 
of R_h to the nearest tenth.
* * * * *
    (d) Evaluate the calculated flow rate-to-load ratios (or gross heat 
rates) as follows.
    (1) Perform a separate data analysis for each fuel flowmeter system 
following the procedures of this section. Base each analysis on a 
minimum of 168

[[Page 40462]]

hours of data. If, for a particular fuel flowmeter system, 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 system accuracy 
test was performed, a flow-to-load (or GHR) evaluation is not required 
for that flowmeter system for that calendar quarter. A one-quarter 
extension of the deadline for the next fuel flowmeter system 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) For a unit that normally co-fires different types of fuel 
(e.g., oil and natural gas), include the contribution of each type of 
fuel in the value of (Heat Input)_h, when using Equation 
D-1e.
* * * * *
    (h) * * * For units that normally co-fire different types 
of fuel, if the GHR option is used, apply the test results to each fuel 
flowmeter system used during the quarter.
2.1.7.3Optional Data Exclusions
    (a) If E_f 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. 
Specifically, the R_h or (GHR)_h values for the 
following hours may be considered non-representative:
    (1) For units that do not normally co-fire fuels, any hour in which 
the unit combusted another fuel in addition to the fuel measured by the 
fuel flowmeter being tested; or
    (2) Any hour for which the load differed by more than &plusmn; 15.0 
percent from the load during either the preceding hour or the 
subsequent hour; or
    (3) For units that normally co-fire different fuels, any hour in 
which the unit burned only one type of fuel; or
    (4) Any hour for which the unit load was in the lower 25.0 percent 
of the range of operation, as defined in section 6.5.2.1 of appendix A 
to this part (unless operation in the lower 25.0 percent of the range 
is considered normal for the unit).
    (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.
* * * * *
2.1.7.5Test Results
* * * * *
Table D-3. Baseline Information and Test Results For Fuel 
Flow-to-Load Test

[[Page 40463]]
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.012
2.2Oil Sampling and Analysis

* * * * *

[[Page 40464]]
[GRAPHIC]
[TIFF OMITTED]
TR12JN02.013

[[Page 40465]]

* * * * *
2.2.4.2Sampling 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.
2.2.4.3Sampling 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, 
consistent