using the higher heating value of the fuel (heat input from duct
burners is not included).
    Excess emissions means a specified averaging period over which
either:
    (1) The CO2 emissions rate of your affected stationary
combustion turbine exceeds the applicable emissions standard in Table 2
of this subpart or Sec.  60.4330; or
    (2) The recorded value of a particular monitored parameter is
outside the acceptable range specified in the parameter monitoring plan
for the affected unit.
    Gross energy output means:
    (1) The gross electric or direct mechanical output from both the
combustion turbine engine and any associated steam turbine(s) or
integrated equipment plus any useful thermal output measured relative
to ISO conditions (except for GHG calculations in Sec.  60.4374 as only
75 percent credit is given) that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application).
    (2) For a CHP stationary combustion turbine where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on a rolling 3-year basis, the
sum of the gross electric or direct mechanical output from both the
combustion turbine engine and any associated steam turbine(s) divided
by 0.95 plus any useful thermal output measured relative to ISO
conditions (except for GHG calculations in Sec.  60.4374 as only 75
percent credit is given) that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application).
    Net-electric output means:
    (1) The gross electric sales to the utility power distribution
system minus purchased power on a 3 calendar year rolling average
basis; or
    (2) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on a 3 calendar year rolling
average basis, the gross electric sales to the utility power
distribution system minus purchased power of the thermal

host facility or facilities on a three calendar year rolling average
basis.
    Operating month means a calendar month during which any fuel is
combusted in the affected stationary combustion turbine.
    Potential electric output means 33 percent or the design electric
output efficiency on a net output basis (at the election of the owner/
operator of the affected facility) multiplied by the base load rating
(expressed in MMBtu/h) of the stationary combustion turbine, multiplied
by 10\6\ Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh,
and multiplied by 8,760 h/yr (e.g., a 35 percent efficient stationary
combustion turbine with a 100 MW (341 MMBtu/h) fossil-fuel heat input
capacity would have a 310,000 MWh 12-month potential electric output
capacity).
    Stationary combustion turbine means all equipment, including but
not limited to the combustion turbine engine, the fuel, air,
lubrication and exhaust gas systems, control systems, heat recovery
system, steam turbine, fuel compressor, heater, and/or pump, post-
combustion emission control technology, and any ancillary components
and sub-components plus any integrated equipment that provides
electricity or useful thermal output to the combustion turbine engine,
heat recovery system or auxiliary equipment. Stationary means that the
combustion turbine is not self propelled or intended to be propelled
while performing its function. It may, however, be mounted on a vehicle
for portability.
0
14. Table 2 to Subpart KKKK of Part 60 is added to read as follows:

 Table 2 to Subpart KKKK of Part 60--Carbon Dioxide Emission Limits for
                     Stationary Combustion Turbines
  [Note: all numerical values have a minimum of 2 significant figures]
------------------------------------------------------------------------
 Affected stationary combustion turbine       CO2 Emission standard
------------------------------------------------------------------------
Stationary combustion turbine that has   450 kilograms (kg) of CO2 per
 a design heat input to the turbine       megawatt-hour (MWh) of gross
 engine of greater than 250 MW            output (1,000 lb/MWh) on a 12-
 (850MMBtu/h).                            operating month rolling
                                          average.
Stationary combustion turbine that has   500 kg of CO2 per MWh of gross
 a design heat input to the turbine       output (1,100 lb CO2/MWh) on a
 engine greater than 73 MW (250 MMBtu/    12-operating month rolling
 h) and equal to or less than 250 MW      average.
 (850MMBtu/h).
------------------------------------------------------------------------

0
15. Table 3 to Subpart KKKK of Part 60 is added to read as follows:

   Table 3 to Subpart KKKK of Part 60--Applicability of Subpart a General Provisions to Stationary Combustion
                                 Turbine CO2 Emissions Standards in Subpart KKKK
----------------------------------------------------------------------------------------------------------------
                                                             Applies to
  General provisions citation      Subject of citation      subpart KKKK                 Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1....................  Applicability..........  Yes.              ....................................
Sec.   60.2....................  Definitions............  Yes.              ....................................
Sec.   60.3....................  Units and Abbreviations  Yes.              ....................................
Sec.   60.4....................  Address................  Yes.              ....................................
Sec.   60.5....................  Determination of         Yes.              ....................................
                                  construction or
                                  modification.
Sec.   60.6....................  Review of plans........  Yes.              ....................................
Sec.   60.7....................  Notification and         Yes               Only the requirements to submit the
                                  Recordkeeping.                             notification in Sec.   60.7(a)(1)
                                                                             and (a)(3).
Sec.   60.8....................  Performance tests......  No.               ....................................
Sec.   60.9....................  Availability of          Yes.              ....................................
                                  Information.
Sec.   60.10...................  State authority........  Yes.              ....................................
Sec.   60.11...................  Compliance with          No.               ....................................
                                  standards and
                                  maintenance
                                  requirements.
Sec.   60.12...................  Circumvention..........  Yes.              ....................................
Sec.   60.13...................  Monitoring requirements  Yes.              ....................................
Sec.   60.14...................  Modification...........  No.               ....................................
Sec.   60.15...................  Reconstruction.........  No.               ....................................
Sec.   60.16...................  Priority list..........  No.
Sec.   60.17...................  Incorporations by        Yes.              ....................................
                                  reference.
Sec.   60.18...................  General control device   No.               ....................................
                                  requirements.
Sec.   60.19...................  General notification     Yes.              ....................................
                                  and reporting
                                  requirements.
----------------------------------------------------------------------------------------------------------------

0
16. Part 60 is amended by adding subpart TTTT to read as follows:

Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions
for Electric Utility Generating Units

Sec.

Applicability

60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?

Emission Standards

60.5515 What greenhouse gases are regulated by this subpart?
60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

60.5525 What are my general requirements for complying with this
subpart?
60.5530 Affirmative defense for violation of emission standards
during malfunction

Monitoring and Compliance Determination Procedures

60.5535 How do I monitor and collect data to demonstrate compliance?

60.5540 How do I demonstrate compliance with my CO2
emissions standard and determine excess emissions?

Notifications, Reports, and Records

60.5550 What notifications must I submit and when?
60.5555 What reports must I submit and when?
60.5560 What records must I maintain?
60.5565 In what form and how long must I keep my records?

Other Requirements and Information

60.5570 What parts of the General Provisions apply to my affected
facility?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?

Applicability

Sec.  60.5508  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from a
steam generating unit, IGCC, or a stationary combustion turbine that
commences construction after [DATE OF PUBLICATION IN THE FEDERAL
REGISTER].

Sec.  60.5509  Am I subject to this subpart?

    (a) Except as provided for in paragraph (b) of this section, the
subpart applies to any steam generating unit, IGCC, or stationary
combustion turbine that commences construction after [DATE OF
PUBLICATION IN THE FEDERAL REGISTER] that meets the relevant
applicability conditions in paragraphs (a)(1) and (a)(2) of this
section.
    (1) A steam generating unit or IGCC that has a design heat input
greater than 73 MW (250MMBtu/h) heat input of fossil fuel (either alone
or in combination with any other fuel), combusts fossil fuel for more
than 10.0 percent of the average annual heat input during a 3 year
rolling average basis, and was constructed for the purpose of
supplying, and supplies, one-third or more of its potential electric
output and more than 219,000 MWh net-electric output to a utility
distribution system on an annual basis.
    (2) A stationary combustion turbine that has a design heat input to
the turbine engine greater than 73 MW (250 MMBtu/h), combusts fossil
fuel for more than 10.0 percent of the average annual heat input during
a 3 year rolling average basis, combusts over 90% natural gas on a heat
input basis on a 3 year rolling average basis, and was constructed for
the purpose of supplying, and supplies, one-third or more of its
potential electric output and more than 219,000 MWh net-electrical
output to a utility distribution system on a 3 year rolling average
basis.
    (b) You are not subject to the requirements of this subpart if your
affected facility meets any one of the conditions specified in
paragraphs (b)(1) through (b)(5) of this section.
    (1) The proposed Wolverine EGU project described in Permit to
Install No. 317-07 issued by the Michigan Department of Environmental
Quality, Air Quality Division, effective June 29, 2011 (as revised July
12, 2011).
    (2) The proposed Washington County EGU project described in Air
Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia
Department of Natural Resources, Environmental Protection Division, Air
Protection Branch, effective April 8, 2010, provided that construction
had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
FEDERAL REGISTER].
    (3) The proposed Holcomb EGU project described in Air Emission
Source Construction Permit 0550023 issued by the Kansas Department of
Health and Environment, Division of Environment, effective December 16,
2010, provided that construction had not commenced for NSPS purposes as
of [DATE OF PUBLICATION IN THE FEDERAL REGISTER].
    (4) Your affected facility is a municipal waste combustor unit that
is subject to subpart Eb of this part.
    (5) Your affected facility is a commercial or industrial solid
waste incineration unit that is subject to subpart CCCC of this part.

Emission Standards

Sec.  60.5515  What greenhouse gases are regulated by this subpart?

    (a) The greenhouse gas regulated by this subpart is carbon dioxide
(CO2).
    (b) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG
emissions from affected facilities, the ``pollutant that is subject to
the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
    (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG
emissions from affected facilities, the ``pollutant that is subject to
the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 52.21(b)(49).
    (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 70.2.
    (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 71.2.

Sec.  60.5520  What CO2 emissions standard must I meet?

    For each affected facility subject to this subpart, you must not
discharge from the affected facility stack into the atmosphere any
gases that contain CO2 in excess of the applicable
CO2 emissions standard specified in Table 1 of this subpart.

General Compliance Requirements

Sec.  60.5525  What are my general requirements for complying with this
subpart?

    (a) You must be in compliance with the emission standards in this
subpart that apply to your affected facility at all times. However, you
must make a compliance determination only at the end of the applicable
operating month, as provided in paragraphs (a)(1) and (2) of this
section.
    (1) For each affected facility subject to a CO2
emissions standard based on a 12-operating month rolling average, you
must determine compliance monthly by calculating the average
CO2 emissions rate for the affected facility at the end of
each 12-operating month period.
    (2) For each affected facility subject to a CO2
emissions standard based on an 84-operating month rolling average, you
must determine compliance monthly by calculating the average
CO2 emissions rate for the affected facility at the end of
each 84-operating month period.
    (b) At all times you must operate and maintain each affected
facility, including associated equipment and monitoring equipment, in a
manner consistent with safety and good air pollution control practice.
The Administrator will determine if you are using consistent operation
and maintenance procedures based on information available to the
Administrator that may include, but is not limited to, fuel use
records, monitoring results, review of operation and maintenance
procedures and

records, review of reports required by this subpart, and inspection of
the facility.
    (c) You must conduct an initial compliance determination for your
affected facility for the applicable emissions standard in Sec.
60.5520, according to the requirements in this subpart, within 30 days
after the end of the initial compliance period for the CO2
emissions standards applicable to your affected facility (i.e., 12-
operating months or 84-operating months). The first operating month
included in this compliance period is the month in which emissions
reporting is required to begin under Sec.  75.64(a) of this chapter.

Sec.  60.5530  Affirmative defense for violation of emission standards
during malfunction.

    In response to an action to enforce the standards set forth in
Sec.  60.5520, you may assert an affirmative defense to a claim for
civil penalties for violations of such standards that are caused by
malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be
assessed if you fail to meet your burden of proving all of the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
    (a) Assertion of affirmative defense. To establish the affirmative
defense in any action to enforce such a standard, you must timely meet
the reporting requirements in paragraph (b) of this section, and must
prove by a preponderance of evidence that:
    (1) The violation:
    (i) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner; and
    (ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices;
    (iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for;
    (iv) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance;
    (2) Repairs were made as expeditiously as possible when the
violation occurred;
    (3) The frequency, amount and duration of the violation (including
any bypass) were minimized to the maximum extent practicable;
    (4) If the violation resulted from a bypass of control equipment or
a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage;
    (5) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health;
    (6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices;
    (7) All of the actions in response to the violation were documented
by properly signed, contemporaneous operating logs;
    (8) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the violation resulting from the malfunction event at
issue. The analysis shall also specify, using best monitoring methods
and engineering judgment, the amount of any emissions that were the
result of the malfunction.
    (b) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator to
demonstrate, with all necessary supporting documentation, that it has
met the requirements set forth in paragraph (a) of this section. This
affirmative defense report is due after the initial occurrence of the
exceedance of the standard in Sec.  60.5520, and on the same quarterly
reporting schedule as in Sec.  60.5555 (which may be the end of any
applicable averaging period). If such quarterly report is due less than
45 days after the initial occurrence of the violation, the affirmative
defense report may be included in the following quarterly report
required in Sec.  60.5555(a).

Monitoring and Compliance Determination Procedures

Sec.  60.5535  How do I monitor and collect data to demonstrate
compliance?

    (a) You must prepare a monitoring plan in accordance with the
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (b) You must measure the hourly CO2 mass emissions from
each affected facility using the procedures in paragraphs (b)(1)
through (5) of this section, except as provided in paragraph (c) of
this section.
    (1) You must install, certify, operate, maintain, and calibrate a
CO2 continuous emission monitoring system (CEMS) to directly
measure and record CO2 concentrations in the affected
facility exhaust gases emitted to the atmosphere and an exhaust gas
flow rate monitoring system according to Sec.  75.10(a)(3)(i) of this
chapter. If you measure CO2 concentration on a dry basis,
you must also install, certify, operate, maintain, and calibrate a
continuous moisture monitoring system, according to Sec.  75.11(b) of
this chapter.
    (2) For each monitoring system you use to determine the
CO2 mass emissions, you must meet the applicable
certification and quality assurance procedures in Sec.  75.20 of this
chapter and Appendices B and D to part 75 of this chapter.
    (3) You must use a laser device to measure the dimensions of each
exhaust gas stack or duct at the flow monitor and the reference method
sampling locations prior to the initial setup (characterization) of the
flow monitor. For circular stacks, you must measure the diameter at
three or more distinct locations and average the results. For
rectangular stacks or ducts, you must measure each dimension (i.e.,
depth and width) at three or more distinct locations and average the
results. If the flow rate monitor or reference method sampling site is
relocated, you must repeat these measurements at the new location.
    (4) You must use only unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions from the affected
facility; you must not apply the bias adjustment factors described in
section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust
gas flow rate data.
    (5) If you choose to use Method 2 in Appendix A-1 to this part to
perform the required relative accuracy test audits (RATAs) of the part
75 flow rate monitoring system, you must use a calibrated Type-S pitot
tube or pitot tube assembly. You must not use the default Type-S pitot
tube coefficient.
    (c) If your affected facility exclusively combusts liquid fuel and/
or gaseous fuel as an alternative to complying with paragraph (b) of
this section, you may determine the hourly CO2 mass
emissions by using Equation G-4 in Appendix G to part 75 of this
chapter according to the requirements in paragraphs (c)(1) and (2) of
this section.
    (1) You must implement the applicable procedures in appendix D to
part 75 of this chapter to determine hourly unit heat input rates
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic
determinations of the gross calorific value (GCV) of each fuel
combusted.
    (2) You may determine site-specific carbon-based F-factors
(Fc) using Equation F-7b in section 3.3.6 of appendix F to
part 75 of this chapter, and you may use these Fc values in
the emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.

    (d) You must install, calibrate, maintain, and operate a sufficient
number of watt meters to continuously measure and record the gross
electric output from the affected facility. If the affected facility is
a CHP facility, you must also install, calibrate, maintain, and operate
meters to continuously determine and record the total useful recovered
thermal energy. For process steam applications, you will need to
install, calibrate, maintain, and operate meters to continuously
determine and record steam flow rate, temperature, and pressure. If the
affected facility has a direct mechanical drive application, you must
submit a plan to the Administrator or delegated authority for approval
of how gross energy output will be determined. Your plan shall ensure
that you install, calibrate, maintain, and operate meters to
continuously determine and record each component of the determination.
    (e) If two or more affected facilities serve a common electric
generator, you must apportion the combined hourly gross output to the
individual affected facilities using a plan approved by the
Administrator (e.g., using steam load or heat input to each affected
EGU). Your plan shall ensure that you install, calibrate, maintain, and
operate meters to continuously determine and record each component of
the determination.
    (f) In accordance with Sec.  60.13(g), if two or more affected
facilities that implement the continuous emission monitoring provisions
in paragraph (b) of this section share a common exhaust gas stack and
are subject to the same emissions standard under Sec.  60.5520, you may
monitor the hourly CO2 mass emissions at the common stack in
lieu of monitoring each EGU separately. If you choose this option, the
hourly gross load (electric, thermal, and/or mechanical, as applicable)
must be the sum of the hourly loads for the individual affected
facility and you must express the operating time as ``stack operating
hours'' (as defined in Sec.  72.2 of this chapter). If you attain
compliance with the applicable emissions standard in Sec.  60.5520 at
the common stack, each affected facility sharing the stack is in
compliance.
    (g) In accordance with Sec.  60.13(g), if the exhaust gases from an
affected facility that implements the continuous emission monitoring
provisions in paragraph (b) of this section are emitted to the
atmosphere through multiple stacks (or if the exhaust gases are routed
to a common stack through multiple ducts and you elect to monitor in
the ducts), you must monitor the hourly CO2 mass emissions
and the ``stack operating time'' (as defined in Sec.  72.2 of this
chapter) at each stack or duct separately. In this case, you must
determine compliance with the applicable emissions standard in Sec.
60.5520 by summing the CO2 mass emissions measured at the
individual stacks or ducts and dividing by the total gross output for
the affected facility.

Sec.  60.5540  How do I demonstrate compliance with my CO2
emissions standard and determine excess emissions?

    (a) You must calculate the CO2 mass emissions rate for
your affected facility by using the hourly CO2 mass
emissions and total gross output data determined and recorded according
to the procedures in Sec.  60.5535 for each operating hour in the
compliance period for the CO2 emissions standard applicable
to the affected facility (i.e., 12- or 84-operating month rolling
average period), and the calculation procedures in paragraphs (a)(1)
through (a)(5) of this section.
    (1) You can only use operating hours in the compliance period for
the compliance determination calculation if valid data are obtained for
all parameters you used to determine the hourly CO2 mass
emissions and the gross output data are used for the compliance
determination calculation. You must not include operating hours in
which you used the substitute data provisions of part 75 of this
chapter for any of those parameters in the calculation. For the
compliance determination calculation, you must obtain valid hourly
CO2 mass emission values for a minimum of 95 percent of the
operating hours in the compliance period for the CO2
emissions standard applicable to the affected facility.
    (2) You must calculate the total CO2 mass emissions by
summing the valid hourly CO2 mass emissions values for all
of the operating hours in the applicable compliance period.
    (3) For each operating hour of the compliance period that you used
in paragraph (a)(2) of this section to calculate the total
CO2 mass emissions, you must determine the affected
facility's corresponding hourly gross output according to the
procedures in paragraphs (a)(3)(i) and (ii) of this section, as
appropriate for the type of affected facility. For an operating hour in
which there is no gross electric load, but there is mechanical or
useful thermal output, you must still determine the gross output for
that hour. In addition, for operating hours in which there is no useful
output, you still need to determine the CO2 emissions for
that hour.
    (i) Calculate Pgross for your affected facility using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.004

Where: a
Pgross = Gross energy output of your affected facility in
megawatt-hours in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected facility's integrated equipment
that provides electricity or mechanical energy to the affected
facility or auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater
pumps at steam generating units in MWh. Not applicable to stationary
combustion turbines or IGCC facilities.
(Pt)PS = Useful thermal energy output of steam measured
relative to ISO conditions that is used for applications that do not
generate additional electricity, produce mechanical energy output,
or enhance the performance of the affected facility. Calculated
using the equation specified in paragraph (g)(3)(iii)(B) of this
section in MWh.
(Pt)HR = Hourly useful thermal energy output measured
relative to ISO conditions from heat recovery that is used for
applications other than steam generation or performance enhancement
of the affected facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO
conditions from any integrated equipment that provides thermal
energy to the affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a combined heat and power affected facility where
at least on an annual basis 20.0 percent of the total gross energy
output consists of electric or direct mechanical output and 20.0
percent of the total gross energy output consists of useful thermal
energy output on a rolling 3 year basis.
    T = 1.0 for all other affected facilities.

    (ii) If applicable to your affected facility, you must calculate
(Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.005

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (4) You must calculate the total gross output for the affected
facility's compliance period by summing the hourly gross output values
for the affected facility that you determined from paragraph (a)(2) of
this section for all of the operating hours in the applicable
compliance period.
    (5) You must calculate the CO2 mass emissions rate for
the affected facility by dividing the total CO2 mass
emissions value calculated according to the procedures in paragraph
(a)(2) of this section by the total gross output value calculated
according to the procedures in paragraph (a)(4) of this section.
    (b) If the CO2 mass emissions rate for your affected
facility that you determined according to the procedures specified in
paragraph (a) of this section is less than or equal to the
CO2 emissions standard in Table 1 of this subpart applicable
to the affected facility, then your affected facility is in compliance
with the emissions standard. If the average CO2 mass
emissions rate is greater than the CO2 emissions standard in
Table 1 of this subpart applicable to the affected facility, then your
affected facility has excess CO2 emissions.

Notification, Reports, and Records

Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit the notifications specified in
Sec. Sec.  60.7(a)(1) and (a)(3) and 60.19, as applicable to your
affected facility.
    (b) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable to your affected facility.

Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports according to paragraphs (a)
through (d) of this section, as applicable.
    (1) For affected facilities that are required by Sec.  60.5525 to
conduct initial and on-going compliance determinations on a 12- or 84-
operating month rolling average basis for the standard in Sec.  60.5520
you must submit electronic quarterly reports as follows. After you have
accumulated the first 12-operating months for the affected facility
(or, the first 84-operating months for an affected facility electing to
comply with the 84-operating month standard), you must submit a report
for the calendar quarter that includes the twelfth (or eighty-fourth)
operating month no later than 30 days after the end of that quarter.
Thereafter, you must submit a report for each subsequent calendar
quarter, no later than 30 days after the end of the quarter.
    (2) In each quarterly report you must include the following
information, as applicable:
    (i) Each rolling average CO2 mass emissions rate for
which the last (12th or eighty-fourth) operating month in a 12- or 84-
operating month compliance period falls within the calendar quarter.
You must calculate each average CO2 mass emissions rate
according to the procedures in Sec.  60.5540. You must report the dates
(month and year) of the first and twelfth (or eighty-fourth) operating
months in each compliance period for which you performed a
CO2 mass emissions rate calculation. If there are no
compliance periods that end in the quarter, you must include a
statement to that effect;
    (ii) If one or more compliance periods end in the quarter you must
identify each operating month in the calendar quarter with excess
CO2 emissions;
    (iii) The percentage of valid CO2 mass emission rates
(as defined in Sec.  60.5540) in each 12- or 84-operating month
compliance period described in paragraph (a)(1)(i) of this section
(i.e., the total number of valid CO2 mass emission rates in
that period divided by the total number of operating hours in that
period, multiplied by 100 percent); and
    (iv) The CO2 emissions standard (as identified in Table
1 of this subpart) with which your affected facility is complying.
    (3) In the final quarterly report of each calendar year, you must
include the following:
    (i) Gross electric output sold to an electric grid over the 4
quarters of the calendar year; and
    (ii) The potential electric output of the facility.
    (b) You must submit all electronic reports required under paragraph
(a) of this section using the Emissions Collection and Monitoring Plan
System (ECMPS) Client Tool provided by the Clean Air Markets Division
in the Office of Atmospheric Programs of EPA.
    (c) You must meet all applicable reporting requirements and submit
reports as required under subpart G of part 75 of this chapter.
    (d) If your affected unit employs geologic sequestration to meet
the applicable emission limit, you must report in accordance with the
requirements of 40 CFR part 98, subpart PP and either:
    (1) if injection occurs onsite, report in accordance with the
requirements of 40 CFR part 98, subpart RR, or
    (2) if injection occurs offsite, transfer the captured
CO2 to a facility or facilities that reports in accordance
with the requirements of 40 CFR part 98, subpart RR.

Sec.  60.5560  What records must I maintain?

    (a) You must maintain records of the information you used to
demonstrate compliance with this subpart as specified in Sec.  60.7(b)
and (f).
    (b) You must follow the applicable recordkeeping requirements and
maintain records as required under subpart F of part 75 of this
chapter.
    (c) You must keep records of the calculations you performed to
determine the total CO2 mass emissions for:
    (1) Each operating month (for all affected units);
    (2) Each compliance period, including, as applicable, each 12-
operating month compliance period and the 84-operating month compliance
period.
    (d) You must keep records of the applicable data recorded and
calculations performed that you used to determine your affected
facility's gross output for each operating month.
    (e) You must keep records of the calculations you performed to
determine the percentage of valid CO2 mass emission rates in
each compliance period.
    (f) You must keep records of the calculations you performed to
assess compliance with each applicable CO2 mass emissions
standard in Sec.  60.5520.
    (g) You must keep records of the calculations you performed to
determine any site-specific carbon-based F-factors you used in the
emissions calculations (if applicable).

Sec.  60.5565  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available
for expeditious review.
    (b) You must maintain each record for 5 years after the date of
each occurrence, measurement, maintenance, corrective action, report,
or record except those records required to demonstrate

compliance with an 84-operating month compliance period. You must
maintain records required to demonstrate compliance with an 84-
operating month compliance period for at least 10 years following the
date of each occurrence, measurement, maintenance, corrective action,
report, or record.
    (c) You must maintain each record on site for at least 2 years
after the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec.  60.7. You may maintain
the records off site and electronically for the remaining year(s) as
required by this subpart.

Other Requirements and Information

Sec.  60.5570  What parts of the General Provisions apply to my
affected facility?

    Notwithstanding any other provision of this chapter, certain parts
of the General Provisions in Sec. Sec.  60.1 through 60.19, listed in
Table 2 of this subpart, do not apply to your affected facility.

Sec.  60.5575  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the EPA, or a
delegated authority such as your state, local, or tribal agency. If the
Administrator has delegated authority to your state, local, or tribal
agency, then that agency (as well as the EPA) has the authority to
implement and enforce this subpart. You should contact your EPA
Regional Office to find out if this subpart is delegated to your state,
local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this
subpart to a state, local, or tribal agency, the Administrator retains
the authorities listed in paragraphs (b)(1) through (5) of this section
and does not transfer them to the state, local, or tribal agency. In
addition, the EPA retains oversight of this subpart and can take
enforcement actions, as appropriate.
    (1) Approval of alternatives to the emission standards.
    (2) Approval of major alternatives to test methods.
    (3) Approval of major alternatives to monitoring.
    (4) Approval of major alternatives to recordkeeping and reporting.
    (5) Performance test and data reduction waivers under Sec.
60.8(b).

Sec.  60.5580  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subpart A (General
Provisions of this part).
    Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
    Base load rating means the maximum amount of heat input (fuel) that
a steam generating unit can combust on a steady state basis, as
determined by the physical design and characteristics of the steam
generating unit at ISO conditions. For a stationary combustion turbine,
baseload means 100 percent of the design heat input capacity of the
simple cycle portion of the stationary combustion turbine at ISO
conditions (heat input from duct burners is not included).
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17),
coal refuse, and petroleum coke. Synthetic fuels derived from coal for
the purpose of creating useful heat, including but not limited to
solvent-refined coal, gasified coal (not meeting the definition of
natural gas), coal-oil mixtures, and coal-water mixtures are included
in this definition for the purposes of this subpart.
    Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
    Combined cycle facility means an electric generating unit that uses
a stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
    Combined heat and power facility or CHP facility, (also known as
``cogeneration'') means an electric generating unit that that use a
steam-generating unit or stationary combustion turbine to
simultaneously produce both electric (or mechanical) and useful thermal
energy from the same primary energy source.
    Distillate oil means fuel oils that contain no more than 0.05
weight percent nitrogen and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17);
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec.  60.17); kerosene, as defined by the American Society of Testing
and Materials in ASTM D3699 (incorporated by reference, see Sec.
60.17); biodiesel as defined by the American Society of Testing and
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17);
or biodiesel blends as defined by the American Society of Testing and
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
    Excess emissions means a specified averaging period over which the
CO2 emissions rate is higher than the applicable emissions
standard located in Table 1 of this subpart.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at ISO
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Gross energy output means:
    (1) For stationary combustion turbines and IGCC facilities, the
gross electric or direct mechanical output from both the unit
(including, but not limited to, output from steam turbine(s),
combustion turbine(s), and gas expander(s)) plus 75 percent of the
useful thermal output measured relative to ISO conditions that is not
used to generate additional electric or mechanical output or to enhance
the performance of the unit (e.g., steam delivered to an industrial
process for a heating application).
    (2) For electric utility steam generating units, the gross electric
or mechanical output from the affected facility (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) minus any electricity used to power the feedwater
pumps plus 75 percent of the useful thermal output measured relative to
ISO conditions that is not used to generate additional electric or
mechanical output or to enhance the performance of the unit (e.g.,
steam delivered to an industrial process for a heating application);
    (3) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and 20.0 percent of the total gross energy output
consists of thermal output on a rolling 3 year basis, the gross
electric or mechanical output from the affected facility (including,
but not limited to, output from steam turbine(s), combustion
turbine(s), and gas expander(s)) minus any electricity used to power
the feedwater pumps (the electric auxiliary load of boiler feedwater
pumps is not applicable to

IGCC facilities), that difference divided by 0.95, plus 75 percent of
the useful thermal output measured relative to ISO conditions that is
not used to generate additional electric or mechanical output or to
enhance the performance of the unit (e.g., steam delivered to an
industrial process for a heating application).
    Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
    Integrated gasification combined cycle facility or IGCC facility
means a combined cycle stationary combustion turbine that is designed
to burn fuels containing 50 percent (by heat input) or more solid-
derived fuel not meeting the definition of natural gas. The
Administrator may waive the 50 percent solid-derived fuel requirement
during periods of the gasification system construction, startup and
commissioning, shutdown, or repair. No solid fuel is directly burned in
the unit during operation.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
    Liquid fuel means any fuel that is present as a liquid at ISO
conditions and includes, but is not limited to, distillate oil and
residual oil.
    Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal energy, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
    Net-electric output means:
    (1) The gross electric sales to the utility power distribution
system minus purchased power on a three calendar year rolling average
basis; or
    (2) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on a 3 calendar year rolling
average basis, the gross electric sales to the utility power
distribution system minus purchased power of the thermal host facility
or facilities on a three calendar year rolling average basis.
    Oil means crude oil or petroleum or a fuel derived from crude oil
or petroleum, including distillate and residual oil, and gases derived
from solid oil-derived fuels (not meeting the definition of natural
gas).
    Operating month means a calendar month during which any fuel is
combusted in the affected facility at any time.
    Potential electric output means 33 percent or the design electric
output efficiency on a net output basis multiplied by the maximum
design heat input capacity (expressed in MMBtu/h) of the steam
generating unit, multiplied by 10\6\ Btu/MMBtu, divided by 3,413 Btu/
KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35
percent efficient affected facility with a 100 MW (341 MMBtu/h) fossil-
fuel heat input capacity would have a 310,000 MWh 12 month potential
electric output capacity).
    Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
    Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emission control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system or auxiliary
equipment. Stationary means that the combustion turbine is not self
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. If a stationary
combustion turbine burns any solid fuel directly it is considered a
steam generating unit.
    Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
    Useful thermal output means the thermal energy made available for
use in any industrial or commercial process, or used in any heating or
cooling application, i.e., total thermal energy made available for
processes and applications other than electric generation, mechanical
output at the affected facility, or to enhance the performance of the
affected facility. Thermal output for this subpart means the energy in
recovered thermal output measured against the energy in the thermal
output at ISO conditions.

       Table 1 to Subpart TTTT of Part 60--CO2 Emission Standards
  [Note: all numerical values have a minimum of 2 significant figures]
------------------------------------------------------------------------
           Affected facility                  CO2 Emission standard
------------------------------------------------------------------------
Stationary combustion turbine that has   450 kilograms (kg) of CO2 per
 a base load rating heat input to the     megawatt-hour (MWh) of gross
 turbine engine of greater than 250 MW    output (1,000 lb/MWh) on a 12-
 (850MMBtu/h).                            operating month rolling
                                          average.
Stationary combustion turbine that has   500 kg of CO2 per MWh of gross
 a design heat input to the turbine       output (1,100 lb CO2/MWh) on a
 engine greater than 73 MW (250 MMBtu/    12-operating month rolling
 h) and equal to or less than 250 MW      average.
 (850MMBtu/h).

Steam generating unit..................  500 kg of CO2 per MWh of gross
                                          energy output (1,100 lb CO2/
                                          MWh) on a 12-operating month
                                          rolling average basis;
                                         or
                                         480 kg of CO2 per MWh of gross
                                          energy output (1,050 lb CO2/
                                          MWh) on an 84-operating month
                                          rolling average basis.
Integrated gasification combined cycle   500 kg of CO2 per MWh of gross
 (IGCC) facility.                         energy output (1,100 lb CO2/
                                          MWh) on a 12-operating month
                                          rolling average basis;
                                         or
                                         480 kg of CO2 per MWh of gross
                                          energy output (1,050 lb CO2/
                                          MWh) on an 84-operating month
                                          rolling average basis.
------------------------------------------------------------------------

        Table 2 to Subpart TTTT of Part 60--Applicability of Subpart a General Provisions to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
                                                             Applies to
  General provisions citation      Subject of citation      subpart TTTT                 Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1....................  Applicability..........  Yes.............
Sec.   60.2....................  Definitions............  Yes.............  Additional terms defined in Sec.
                                                                             60.5580.
Sec.   60.3....................  Units and Abbreviations  Yes.............
Sec.   60.4....................  Address................  Yes.............
Sec.   60.5....................  Determination of         Yes.............
                                  construction or
                                  modification.
Sec.   60.6....................  Review of plans........  Yes.............
Sec.   60.7....................  Notification and         Yes.............  Only the requirements to submit the
                                  Recordkeeping.                             notification in Sec.   60.7(a)(1)
                                                                             and (a)(3).
Sec.   60.8....................  Performance tests......  No..............
Sec.   60.9....................  Availability of          Yes.............
                                  Information.
Sec.   60.10...................  State authority........  Yes.............
Sec.   60.11...................  Compliance with          No..............
                                  standards and
                                  maintenance
                                  requirements.
Sec.   60.12...................  Circumvention..........  Yes.............
Sec.   60.13...................  Monitoring requirements  Yes.............
Sec.   60.14...................  Modification...........  No..............
Sec.   60.15...................  Reconstruction.........  No..............
Sec.   60.16...................  Priority list..........  No..............
Sec.   60.17...................  Incorporations by        Yes.............
                                  reference.
Sec.   60.18...................  General control device   No..............
                                  requirements.
Sec.   60.19...................  General notification     Yes.............
                                  and reporting
                                  requirements.
----------------------------------------------------------------------------------------------------------------

PART 70--STATE OPERATING PERMIT PROGRAMS

0
17. The authority citation for part 70 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

0
18. Section 70.2 is amended:
0
a. By adding in alphabetical order the definition of ``Greenhouse
gases,''
0
b. By revising the introductory text, removing ``or'' from the end of
paragraph (2), adding ``or'' to the end of paragraph (3), and adding
paragraph (4) to the definition of ``Regulated pollutant (for
presumptive fee calculation),'' and
0
c. By revising paragraph (1) to the definition of ``Subject to
regulation.''
    The revision and additions read as follows:

Sec.  70.2  Definitions.

* * * * *
    Greenhouse gases (GHGs) means the air pollutant defined in Sec.
86.1818-12(a) of this chapter as the aggregate group of six greenhouse
gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons,
perfluorocarbons, and sulfur hexafluoride.
* * * * *
    Regulated pollutant (for presumptive fee calculation), which is
used only for purposes of Sec.  70.9(b)(2), means any regulated air
pollutant except the following:
* * * * *
    (4) Greenhouse gases.
* * * * *
    Subject to regulation * * *
    (1) Greenhouse gases shall not be subject to regulation unless, as
of July 1, 2011, the GHG emissions are at a stationary source emitting
or having the potential to emit 100,000 tpy CO2 equivalent
emissions.
* * * * *
0
19. Section 70.9 is amended by revising paragraph (b)(2)(i), and by
adding paragraph (b)(2)(v) to read as follows:

Sec.  70.9  Fee determination and certification.

* * * * *
    (b) * * *
    (2)(i) The Administrator will presume that the fee schedule meets
the requirements of paragraph (b)(1) of this section if it would result
in the collection and retention of an amount not less than $25 per year
[as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv)
of this section] times the total tons of the actual emissions of each
regulated pollutant (for presumptive fee calculation) emitted from part
70 sources and any GHG cost adjustment required under paragraph
(b)(2)(v) of this section.
* * * * *
    (v) GHG cost adjustment. The amount calculated in paragraph
(b)(2)(i) of this section shall be increased by the GHG cost adjustment
determined as follows:

For each activity identified in the following table, multiply the
number of activities performed by the permitting authority by the
burden hours per activity, and then calculate a total number of burden
hours for all activities. Next, multiply the burden hours by the
average cost of staff time, including wages, employee benefits and
overhead.

------------------------------------------------------------------------
                                                                Burden
                          Activity                             hours per
                                                               activity
------------------------------------------------------------------------
GHG completeness determination (for initial permit or                 43
 updated application).......................................
GHG evaluation for a modification or related permit action..           7
GHG evaluation at permit renewal............................          10
------------------------------------------------------------------------

* * * * *

PART 71--FEDERAL OPERATING PERMIT PROGRAMS

0
20. The authority citation for part 71 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

0
21. Section 71.2 is amended:
0
a. By adding in alphabetical order the definition of ``Greenhouse
gases,''
0
b. By removing ``or'' from the end of paragraph (2), adding ``or'' to
the end of paragraph (3), and adding paragraph (4) to the definition of
``Regulated pollutant (for fee calculation),'' and
0
c. By revising paragraph (1) of the definition of ``Subject to
regulation.''
    The revisions and additions read as follows:

Sec.  71.2  Definitions.

* * * * *
    Greenhouse gases (GHGs) means the air pollutant defined in Sec.
86.1818-12(a) of this chapter as the aggregate group of six greenhouse
gases: carbon dioxide, nitrous oxide, methane, hydrofluorocarbons,
perfluorocarbons, and sulfur hexafluoride.
* * * * *
    Regulated pollutant (for fee calculation), which is used only for
purposes of Sec.  71.9(c), means any ``regulated air pollutant'' except
the following:
* * * * *
    (4) Greenhouse gases.
* * * * *
    Subject to regulation * * *
    (1) Greenhouse gases shall not be subject to regulation unless, as
of July 1, 2011, the GHG emissions are at a stationary source emitting
or having the potential to emit 100,000 tpy CO2 equivalent
emissions.
* * * * *
0
22. Section 71.9 is amended by:
0
a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and
0
b. Adding paragraph (c)(8).
    The revisions and additions read as follows:

Sec.  71.9  Permit fees.

* * * * *
    (c) * * *
    (1) For part 71 programs that are administered by EPA, each part 71
source shall pay an annual fee which is the sum of:
    (i) $32 per ton (as adjusted pursuant to the criteria set forth in
paragraph (n)(1) of this section) times the total tons of the actual
emissions of each regulated pollutant (for fee calculation) emitted
from the source, including fugitive emissions; and
    (ii) Any GHG fee adjustment required under paragraph (c)(8) of this
section.
    (2) * * *
    (i) Where the EPA has not suspended its part 71 fee collection
pursuant to paragraph (c)(2)(ii) of this section, the annual fee for
each part 71 source shall be the sum of:
    (A) $24 per ton (as adjusted pursuant to the criteria set forth in
paragraph (n)(1) of this section) times the total tons of the actual
emissions of each regulated pollutant (for fee calculation) emitted
from the source, including fugitive emissions; and
    (B) Any GHG fee adjustment required under paragraph (c)(8) of this
section.
* * * * *
    (3) For part 71 programs that are administered by EPA with
contractor assistance, the per ton fee shall vary depending on the
extent of contractor involvement and the cost to EPA of contractor
assistance. The EPA shall establish a per ton fee that is based on the
contractor costs for the specific part 71 program that is being
administered, using the following formula: Cost per ton = (E x 32) +
[(1- E) x $ C]
    Where E represents EPA's proportion of total effort (expressed as a
percentage of total effort) needed to administer the part 71 program,
1- E represents the contractor's effort, and C represents the
contractor assistance cost on a per ton basis. C shall be computed by
using the following formula: C = [ B + T + N] divided by 12,300,000
    Where B represents the base cost (contractor costs), where T
represents travel costs, and where N represents nonpersonnel data
management and tracking costs. In addition, each part 71 source shall
pay a GHG fee adjustment for each activity as required under paragraph
(c)(8) of this section.
    (4) For programs that are delegated in part, the fee shall be
computed using the following formula: Cost per ton = (E x 32) + (D x
24) + [(1- E - D) x $ C]
    Where E and D represent, respectively, the EPA and delegate agency
proportions of total effort (expressed as a percentage of total effort)
needed to administer the part 71 program, 1- E - D represents the
contractor's effort, and C represents the contractor assistance cost on
a per ton basis. C shall be computed using the formula for contractor
assistance cost found in paragraph (c)(3) of this section and shall be
zero if contractor assistance is not utilized. In addition, each part
71 source shall pay a GHG fee adjustment for each activity as required
under paragraph (c)(8) of this section.
* * * * *
    (8) GHG fee adjustment. The annual fee shall be increased by a GHG
fee adjustment for any source that has initiated an activity listed in
the following table since the fee was last paid. The GHG fee adjustment
shall be equal to the set fee provided in the table for each activity
that has been initiated since the fee was last paid:

------------------------------------------------------------------------
                           Activity                              Set fee
------------------------------------------------------------------------
GHG completeness determination (for initial permit or updated     $2,236
 application).................................................
GHG evaluation for a permit modification or related permit           364
 action.......................................................
GHG evaluation at permit renewal..............................       520
------------------------------------------------------------------------

* * * * *

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
23. The authority citation for part 98 is revised to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart PP--Suppliers of Carbon Dioxide

0
24. Section 98.426 is amended by adding paragraph (h) to read as
follows:

Sec.  98.426   Data reporting requirements.

* * * * *
    (h) If you capture a CO2 stream from an electricity
generating unit that is subject to subpart D of this part and transfer
CO2 to any facilities that are subject to subpart RR of this
part, you must:
    (1) Report the facility identification number associated with the
annual GHG report for the facility that is subject to subpart D of this
part,
    (2) Report each facility identification number associated with the
annual GHG

reports for each facility that is subject to subpart RR of this part to
which CO2 is transferred, and
    (3) Report the annual quantity of CO2 in metric tons
that is transferred to each facility that is subject to subpart RR of
this part.
0
25. Section 98.427 is amended by adding paragraph (d) to read as
follows:

Sec.  98.427  Records that must be retained.

* * * * *
    (d) Facilities subject to Sec.  98.426(h) must retain records of
CO2 in metric tons that is transferred to each facility that
is subject to subpart RR of this part.
[FR Doc. 2013-28668 Filed 12-27-13; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 80, Number 116 (Wednesday, June 17, 2015)]
[Notices]
[Pages 34635-34636]
[FR Doc No: 2015-14872]

-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 2413-117]

Georgia Power Company; Notice of Proposed Restricted Service List
for a Programmatic Agreement

    Rule 2010 of the Federal Energy Regulatory Commission's
(Commission) Rules of Practice and Procedure, 18 CFR 385.2010, provides
that, to eliminate unnecessary expense or improve administrative
efficiency, the Secretary may establish a restricted service list for a
particular phase or issue in a proceeding. The restricted service list
should contain the names of persons on the service list who, in the
judgment of the decisional authority establishing the list, are active
participants with respect to the phase or issue in the proceeding for
which the list is established.
    The Commission staff is consulting with the Georgia Department of
Natural Resources--Historic Preservation Division (Georgia SHPO) and
the Advisory Council on Historic Preservation (Advisory Council)
pursuant to the Advisory Council's regulations, 36 CFR part 800,
implementing section 106 of the National Historic Preservation Act, as
amended (54 U.S.C. 306108), to prepare a Programmatic Agreement for
managing properties included in, or eligible for inclusion in, the
National Register of Historic Places at the Wallace Dam Pumped Storage
Project.
    The Programmatic Agreement, when executed by the Commission, the
Georgia SHPO, and the Advisory Council, would satisfy the Commission's
section 106 responsibilities for all individual undertakings carried
out in accordance with the license until the license expires

or is terminated (36 CFR 800.13(e)). The Commission's responsibilities
pursuant to section 106 for the project would be fulfilled through the
Programmatic Agreement, which the Commission staff proposes to draft in
consultation with certain parties listed below.
    Georgia Power Company, as licensee for the Wallace Dam Pumped
Storage Project, is invited to participate in consultations to develop
the Programmatic Agreement and to sign as a concurring party to the
Programmatic Agreement. For purposes of commenting on the Programmatic
Agreement, we propose to restrict the service list for Project No.
2413-117 as follows:

Dr. John Eddins, Advisory Council on Historic Preservation, 401 F
Street NW., Suite 308, Washington, DC 20001-2637
Christine Quinn, Georgia Department of Natural Resources--Historic
Preservation Division, 254 Washington Street SW., Atlanta, GA 30334
Courtenay R. O'Mara, P.E., Southern Company Generation, 241 Ralph
McGill Blvd. NE., BIN 10193, Atlanta, GA 30308
Joseph Charles, Georgia Power Company, 241 Ralph McGill Blvd. NE., BIN
10151, Atlanta, GA 30308
Wanda Greene, Georgia Power Company, 241 Ralph McGill Blvd. NE., BIN
10151, Atlanta, GA 30308
Hallie M. Meushaw, Troutman Sanders LLP, Bank of America Plaza, 600
Peachtree Street NE., Suite 5200, Atlanta, GA 30308
Thomas M. Dozier, District Ranger, Chattahoochee-Oconee National
Forest, Oconee National Forest, 1199 Madison Road, Eatonton, GA 31024
Lisa C. Baker, Acting THPO, United Keetoowah Band of Cherokee Indians
in Oklahoma, P.O. Box 746, Tahlequah, OK 74465
Tyler Howe, THPO, Eastern Band of Cherokee Indians, P.O. Box 455,
Cherokee, NC 28719
Principal Chief Bill John Baker, Cherokee Nation, P.O. Box 948,
Tahlequah, OK 74465
James Wettstaed, U.S. Forest Service, 1755 Cleveland HWY, Gainesville,
GA 30501
Stacy Lundgren, U.S. Forest Service, 1199 Madison Road, Eatonton, GA
31024

    Any person on the official service list for the above-captioned
proceedings may request inclusion on the restricted service list, or
may request that a restricted service list not be established, by
filing a motion to that effect within 15 days of this notice date. A
copy of any such motion must be filed with the Secretary of the
Commission (888 First Street NE., Washington, DC 20426) and must be
served on each person whose name appears on the official service list.
If no such motions are filed, the restricted service list will be
effective at the end of the 15 day period. Otherwise, a further notice
will be issued ruling on the motion.

    Dated: June 11, 2015.
Kimberly D. Bose,
Secretary.
[FR Doc. 2015-14872 Filed 6-16-15; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 83, Number 123 (Tuesday, June 26, 2018)]
[Rules and Regulations]
[Pages 29665-29667]
[FR Doc No: 2018-13639]

========================================================================
Rules and Regulations
                                                Federal Register
________________________________________________________________________

This section of the FEDERAL REGISTER contains regulatory documents
having general applicability and legal effect, most of which are keyed
to and codified in the Code of Federal Regulations, which is published
under 50 titles pursuant to 44 U.S.C. 1510.

The Code of Federal Regulations is sold by the Superintendent of Documents.

========================================================================

Federal Register / Vol. 83, No. 123 / Tuesday, June 26, 2018 / Rules
and Regulations

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2018-0564; Product Identifier 2018-NE-23-AD; Amendment
39-19315; AD 2018-13-03]
RIN 2120-AA64

Airworthiness Directives; International Aero Engines Turbofan
Engines

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Final rule; request for comments.

-----------------------------------------------------------------------

SUMMARY: We are adopting a new airworthiness directive (AD) for certain
International Aero Engines (IAE) PW1133G-JM, PW1133GA-JM, PW1130G-JM,
PW1127G-JM, PW1127GA-JM, PW1127G1-JM, PW1124G-JM, PW1124G1-JM, and
PW1122G-JM turbofan engines. This AD requires a one-time visual
inspection of the engine fan hub for damage, and removal of parts if
damage or defects are found that are outside the serviceable limits.
This AD was prompted by reports of damage to the engine fan hub. We are
issuing this AD to address the unsafe condition on these products.

DATES: This AD is effective July 11, 2018.
    The Director of the Federal Register approved the incorporation by
reference of a certain publication listed in this AD as of July 11,
2018.
    We must receive comments on this AD by August 10, 2018.

ADDRESSES: You may send comments, using the procedures found in 14 CFR
11.43 and 11.45, by any of the following methods:
     Federal eRulemaking Portal: Go to http://www.regulations.gov. Follow the instructions for submitting comments.
     Fax:<PHONE_NUMBER>.
     Mail: U.S. Department of Transportation, Docket
Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New
Jersey Avenue SE, Washington, DC 20590.
     Hand Delivery: U.S. Department of Transportation, Docket
Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New
Jersey Avenue SE, Washington, DC 20590, between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays.
    For service information identified in this final rule, contact
International Aero Engines, 400 Main Street, East Hartford, CT 06118;
phone:<PHONE_NUMBER>; email: [email protected]; internet: http://fleetcare.pw.utc.com. You may view this service information at the FAA,
Engine and Propeller Standards Branch, 1200 District Avenue,
Burlington, MA 01803. For information on the availability of this
material at the FAA, call<PHONE_NUMBER>. It is also available on the
internet at http://www.regulations.gov by searching for and locating
Docket No. FAA-2018-0564.

Examining the AD Docket

    You may examine the AD docket on the internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2018-
0564; or in person at Docket Operations between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays. The AD docket contains
this final rule, the regulatory evaluation, any comments received, and
other information. The street address for the Docket Operations (phone:
800-647-5527) is listed above. Comments will be available in the AD
docket shortly after receipt.

FOR FURTHER INFORMATION CONTACT: Kevin M. Clark, Aerospace Engineer,
ECO Branch, FAA, 1200 District Avenue, Burlington, MA 01803; phone:
781-238-7088; fax:<PHONE_NUMBER>; email: [email protected].

SUPPLEMENTARY INFORMATION:

Discussion

    We received information concerning damage to the engine fan hub
found during an engine shop visit of an IAE PW1100G-series turbofan
engine. The damage is believed to be the result of the installation of
the inlet cone without using alignment pins, which might lead to bolts
impacting and damaging the engine fan hub. This condition, if not
addressed, could result in uncontained failure of the engine fan hub,
damage to the engine, and damage to the airplane. We are issuing this
AD to address the unsafe condition on these products.

Related Service Information Under 1 CFR Part 51

    We reviewed Pratt & Whitney (PW) Service Bulletin (SB) PW1000G-C-
72-00-0104-00A-930A-D, Issue No. 002, dated May 31, 2018. The SB
describes procedures for performing a one-time visual inspection of the
inlet cone mating face and counter weight flange on the engine fan hub
assembly for surface damage. This service information is reasonably
available because the interested parties have access to it through
their normal course of business or by the means identified in the
ADDRESSES section.

FAA's Determination

    We are issuing this AD because we evaluated all the relevant
information and determined the unsafe condition described previously is
likely to exist or develop in other products of the same type design.

AD Requirements

    This AD requires a one-time visual inspection of the engine fan hub
for damage, and replacement of the engine fan hub if damage or defects
are found that are outside of serviceable limits.

Differences Between the AD and the Service Information

    PW SB PW1000G-C-72-00-0104-00A-930A-D, Issue No. 002, dated May 31,
2018, only applies to PW1100G-JM engine models in service. This AD
applies to all PW1100G-JM engine models certified under type
certificate E00087EN. PW SB PW1000G-C-72-00-0104-00A-930A-D also
excludes from its applicability certain serial numbered engines. We
have no way to determine if these engines have been inspected and are
therefore including these engines in the applicability of this AD.

Interim Action

    We consider this AD interim action. An investigation to determine
the cause of the failure is on-going and we may consider additional
rulemaking if final action is identified.

FAA's Justification and Determination of the Effective Date

    An unsafe condition exists that requires the immediate adoption of
this AD without providing an opportunity for public comments prior to
adoption. The FAA has found that the risk to the flying public
justifies waiving notice and comment prior to adoption of this rule
because the compliance time is less than the time required for public
comment. In addition, all engine fan hubs must be inspected, and if
needed, replaced before further flight. Therefore, we find good cause
that notice and compliance for prior public comment are impracticable.
In addition, for the reasons stated above, we find that good cause
exists for making this amendment effective in less than 30 days.

Comments Invited

    This AD is a final rule that involves requirements affecting flight
safety and was not preceded by notice and an opportunity for public
comment. However, we invite you to send any written data, views, or
arguments about this final rule. Send your comments to an address
listed under the ADDRESSES section. Include the docket number FAA-2018-
0564 and Product Identifier 2018-NE-23-AD at the beginning of your
comments. We specifically invite comments on the overall regulatory,
economic, environmental, and energy aspects of this final rule. We will
consider all comments received by the closing date and may amend this
final rule because of those comments.
    We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We
will also post a report summarizing each substantive verbal contact we
receive about this final rule.

Costs of Compliance

    We estimate that this AD affects 14 engines installed on airplanes
of U.S. registry.
    We estimate the following costs to comply with this AD:

                                                 Estimated Costs
----------------------------------------------------------------------------------------------------------------
                                                                                Cost per      Cost on U.S.
               Action                         Labor cost            Parts cost        product        operators
----------------------------------------------------------------------------------------------------------------
Visual inspection..................  2 work-hours x $85 per hour              $0            $170          $2,380
                                      = $170.
----------------------------------------------------------------------------------------------------------------

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, section 106, describes the
authority of the FAA Administrator. ``Subtitle VII: Aviation Programs''
describes in more detail the scope of the Agency's authority.
    We are issuing this rulemaking under the authority described in
Subtitle VII, Part A, Subpart III, Section 44701: ``General
requirements.'' Under that section, Congress charges the FAA with
promoting safe flight of civil aircraft in air commerce by prescribing
regulations for practices, methods, and procedures the Administrator
finds necessary for safety in air commerce. This regulation is within
the scope of that authority because it addresses an unsafe condition
that is likely to exist or develop on products identified in this
rulemaking action.
    This AD is issued in accordance with authority delegated by the
Executive Director, Aircraft Certification Service, as authorized by
FAA Order 8000.51C. In accordance with that order, issuance of ADs is
normally a function of the Compliance and Airworthiness Division, but
during this transition period, the Executive Director has delegated the
authority to issue ADs applicable to engines, propellers, and
associated appliances to the Manager, Engine and Propeller Standards
Branch, Policy and Innovation Division.

Regulatory Findings

    This AD will not have federalism implications under Executive Order
13132. This AD will not have a substantial direct effect 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.
    For the reasons discussed above, I certify that this AD:
    (1) Is not a ``significant regulatory action'' under Executive
Order 12866,
    (2) Is not a ``significant rule'' under DOT Regulatory Policies and
Procedures (44 FR 11034, February 26, 1979),
    (3) Will not affect intrastate aviation in Alaska, and
    (4) Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

Adoption of the Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA amends 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority:  49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13   [Amended]

0
2. The FAA amends Sec.  39.13 by adding the following new airworthiness
directive (AD):

2018-13-03 International Aero Engines: Amendment 39-19315; Docket
No. FAA-2018-0564; Product Identifier 2018-NE-23-AD.

(a) Effective Date

    This AD is effective July 11, 2018.

(b) Affected ADs

    None.

(c) Applicability

    This AD applies to International Aero Engines (IAE) PW1133G-JM,
PW1133GA-JM, PW1130G-JM, PW1127G-JM, PW1127GA-JM, PW1127G1-JM,
PW1124G-JM, PW1124G1-JM, and PW1122G-JM turbofan engines with serial
numbers (S/Ns) up to and including S/N 770735.

(d) Subject

    Joint Aircraft System Component (JASC) Code 7230, Turbine Engine
Compressor Section.

(e) Unsafe Condition

    This AD was prompted by reports of damage to the engine fan hub.
We are issuing this AD to detect defects, damage, and cracks that
could result in an uncontained failure of the engine fan hub. The
unsafe condition, if not addressed, could result in uncontained
failure of the engine fan hub, damage to the engine, and damage to
the airplane.

(f) Compliance

    Comply with this AD within the compliance times specified,
unless already done.

(g) Required Actions

    Within 90 days after the effective date of this AD:
    (1) For engines installed on an airplane, perform a visual
inspection of the engine fan hub, in accordance with the
Accomplishment Instructions, paragraphs 1.E.(1) to 1.E.(4), of Pratt
& Whitney (PW) Service Bulletin (SB) PW1000G-C-72-00-0104-00A-930A-
D, Issue No. 002, dated May 31, 2018.
    (2) For engines not installed on an airplane, perform a visual
inspection of the engine fan hub, in accordance with the
Accomplishment Instructions, paragraphs 2.D.(1) to 2.D.(4), of PW SB
PW1000G-C-72-00-0104-00A-930A-D, Issue No. 002, dated May 31, 2018.
    (3) If the engine fan hub visual inspection reveals defects or
damage to the engine fan hub that are found outside the serviceable
limits specified in Table 3 in the Accomplishment Instructions of PW
SB PW1000G-C-72-00-0104-00A-930A-D, Issue No. 002, dated May 31,
2018, remove the engine fan hub from service and replace with a part
that is eligible for installation, prior to further flight.

(h) Credit for Previous Actions

    You may take credit for the inspection required by paragraph (g)
of this AD if you performed the inspection before the effective date
of this AD using PW SB PW1000G-C-72-00-0104-00A-930A-D, Original
Issue, dated May 21, 2018.

(i) Alternative Methods of Compliance (AMOCs)

    (1) The Manager, ECO Branch, FAA, has the authority to approve
AMOCs for this AD, if requested using the procedures found in 14 CFR
39.19. In accordance with 14 CFR 39.19, send your request to your
principal inspector or local Flight Standards District Office, as
appropriate. If sending information directly to the manager of the
certification office, send it to the attention of the person
identified in paragraph (j) of this AD. You may email your request
to: [email protected].
    (2) Before using any approved AMOC, notify your appropriate
principal inspector, or lacking a principal inspector, the manager
of the local flight standards district office/certificate holding
district office.

(j) Related Information

    For more information about this AD, contact Kevin M. Clark,
Aerospace Engineer, ECO Branch, FAA, 1200 District Avenue,
Burlington, MA 01803; phone:<PHONE_NUMBER>; fax:<PHONE_NUMBER>; email:
[email protected].

(k) Material Incorporated by Reference

    (1) The Director of the Federal Register approved the
incorporation by reference (IBR) of the service information listed
in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
    (2) You must use this service information as applicable to do
the actions required by this AD, unless the AD specifies otherwise.
    (i) Pratt & Whitney Service Bulletin PW1000G-C-72-00-0104-00A-
930A-D, Issue No. 002, dated May 31, 2018.
    (ii) Reserved.
    (3) For International Aero Engines service information
identified in this AD, contact International Aero Engines, 400 Main
Street, East Hartford, CT 06118; phone:<PHONE_NUMBER>; email:
[email protected]; internet: http://fleetcare.pw.utc.com.
    (4) You may view this service information at FAA, Engine and
Propeller Standards Branch, 1200 District Avenue, Burlington, MA.
For information on the availability of this material at the FAA,
call<PHONE_NUMBER>.
    (5) You may view this service information that is incorporated
by reference at the National Archives and Records Administration
(NARA). For information on the availability of this material at
NARA, call<PHONE_NUMBER>, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.

    Issued in Burlington, Massachusetts, on June 19, 2018.
Robert J. Ganley,
Manager, Engine and Propeller Standards Branch, Aircraft Certification
Service.
[FR Doc. 2018-13639 Filed 6-25-18; 8:45 am]
 BILLING CODE 4910-13-P