identifying number to each account established under paragraphs (a)
through (c) of this section.
    (e) Responsibilities of authorized account representative and
alternate authorized account representative. After the establishment of
a compliance account or general account, the Administrator will accept
or act on a submission pertaining to the account, including, but not
limited to, submissions concerning the deduction or transfer of
CO2 allowances in the account, only if the submission has
been made, signed, and certified in accordance with Sec. Sec.
62.16295(a) and 62.16315 or paragraphs (c)(2)(ii) and (c)(5) of this
section.

Sec.  62.16325  When will CO2 allowances be recorded in compliance
accounts?

    (a) By June 1, 2021, and by June 1 of each year prior to the
beginning of each compliance period thereafter, the Administrator will
record in each facility's compliance account the CO2
allowances allocated to the affected EGUs at the facility in accordance
with Sec.  62.16240(a), or with a state allowance-distribution
methodology approved under subpart UUUU of part 60 of this

chapter, for the upcoming compliance period.
    (b) Except as specified in paragraph (a) of this section, the
Administrator will record an allocation in the appropriate ATCS account
by the date on which any allocation of CO2 allowances to a
recipient must be made by or submitted to the Administrator in
accordance with either Sec.  62.16240 or with state allowance-
distribution methodology approved under subpart UUUU of part 60 of this
chapter.
    (c) When recording the allocation of CO2 allowances to
an affected EGU or other entity in an ATCS account, the Administrator
will assign each CO2 allowance a unique serial number that
will include digits identifying the year of the compliance period for
which the CO2 allowance is allocated.
    (d) By December 1, 2021 and December 1 of each year thereafter, the
Administrator will record in each renewable energy project's general
account, the CO2 allowances allocated from the renewable
energy set-aside to the project in accordance with Sec.  62.16245(a),
for the following year.
    (e) By November 1 of the first year of each compliance period
beginning in 2025, and each compliance period thereafter, the
Administrator will record in each facility's compliance account the
CO2 allowances allocated from the output-based set-aside to
the eligible EGUs at the facility in accordance with Sec.  62.16245(b)
or with a state allowance-distribution methodology approved under
subpart UUUU of part 60 of this chapter, for the following year.

Sec.  62.16330  How must transfers of CO2 allowances be submitted?

    (a) An authorized account representative seeking recordation of a
CO2 allowance transfer must submit the transfer to the
Administrator.
    (b) A CO2 allowance transfer is correctly submitted if:
    (1) The transfer includes the following elements, in a format
prescribed by the Administrator:
    (i) The account numbers established by the Administrator for both
the transferor and transferee accounts;
    (ii) The serial number of each CO2 allowance that is in
the transferor account and is to be transferred; and
    (iii) The name and signature of the authorized account
representative of the transferor account and the date signed; and
    (2) When the Administrator attempts to record the transfer, the
transferor account includes each CO2 allowance identified by
serial number in the transfer.

Sec.  62.16335  When will CO2 allowance transfers be recorded?

    (a) Within 5 business days (except as provided in paragraph (b) of
this section) of receiving a CO2 allowance transfer that is
correctly submitted under Sec.  62.16330, the Administrator will record
a CO2 allowance transfer by moving each CO2
allowance from the transferor account to the transferee account as
specified in the transfer.
    (b) A CO2 allowance transfer to or from a compliance
account that is submitted for recordation after the allowance transfer
deadline for a compliance period and that includes any CO2
allowances allocated for any compliance period before such allowance
transfer deadline will not be recorded until after the Administrator
completes the deductions from such compliance account under Sec.
62.16340 for the compliance period immediately before such allowance
transfer deadline.
    (c) Where a CO2 allowance transfer is not correctly
submitted under Sec.  62.16330, the Administrator will not record such
transfer.
    (d) Within 5 business days of recordation of a CO2
allowance transfer under paragraphs (a) and (b) of the section, the
Administrator will notify the authorized account representatives of
both the transferor and transferee accounts.
    (e) Within 10 business days of receipt of a CO2
allowance transfer that is not correctly submitted under Sec.
62.16330, the Administrator will notify the authorized account
representatives of both accounts subject to the transfer of:
    (1) A decision not to record the transfer; and
    (2) The reasons for such non-recordation.

Sec.  62.16340  How will deductions for compliance with a CO2 emission
standard occur?

    (a) Availability for deduction for compliance. CO2
allowances are available to be deducted for compliance with a
facility's CO2 emission standard for a compliance period
only if the CO2 allowances:
    (1) Were allocated for a year in such compliance period or a prior
compliance period; and
    (2) Are held in the facility's compliance account as of the
allowance transfer deadline for such compliance period.
    (b) Deductions for compliance. After the recordation, in accordance
with Sec.  62.16335, of CO2 allowance transfers submitted by
the allowance transfer deadline for a compliance period, the
Administrator will deduct from each facility's compliance account
CO2 allowances available under paragraph (a) of this section
in order to determine whether the facility meets the CO2
emission standard for such compliance period, as follows:
    (1) Until the amount of CO2 allowances deducted equals
the number of tons of total CO2 emissions from all affected
EGUs at the facility for such compliance period; or
    (2) If there are insufficient CO2 allowances to complete
the deductions in paragraph (b)(1) of this section, until no more
CO2 allowances available under paragraph (a) of this section
remain in the compliance account.
    (c)(1) Identification of CO2 allowances by serial
number. The authorized account representative for a facility's
compliance account may request that specific CO2 allowances,
identified by serial number, in the compliance account be deducted for
emissions or excess emissions for a compliance period in accordance
with paragraph (b) or (d) of this section. In order to be complete,
such request must be submitted to the Administrator by the allowance
transfer deadline for such compliance period and include, in a format
prescribed by the Administrator, the identification of the facility and
the appropriate serial numbers.
    (2) First-in, first-out. The Administrator will deduct
CO2 allowances under paragraph (b) or (d) of this section
from the facility's compliance account in accordance with a complete
request under paragraph (c)(1) of this section or, in the absence of
such request or in the case of identification of an insufficient amount
of CO2 allowances in such request, on a first-in, first-out
accounting basis in the following order:
    (i) Any CO2 allowances that were allocated to the
affected EGUs at the facility and not transferred out of the compliance
account, in the order of recordation; and then
    (ii) Any CO2 allowances that were allocated to any
affected EGU or other entity and transferred to and recorded in the
compliance account pursuant to this subpart, in the order of
recordation.
    (d) Deductions for excess emissions. After making the deductions
for compliance under paragraph (b) of this section for a compliance
period in a year in which the facility has excess emissions, the
Administrator will deduct from the facility's compliance account an
amount of CO2 allowances, allocated for a compliance period
in a prior year or the compliance period in the year of the excess
emissions or in the immediately following year, equal to two times the
number of tons of the facility's excess emissions.

    (e) Recordation of deductions. The Administrator will record in the
appropriate compliance account all deductions from such an account
under paragraphs (b) and (d) of this section.

Sec.  62.16345  What monitoring requirements must I comply with?

    (a) The owner or operator of an affected EGU must prepare a
monitoring plan in accordance with the applicable provisions in Sec.
75.53(g) and (h) of this chapter, unless such a plan is already in
place under another program that requires CO2 mass emissions
to be monitored and reported according to part 75 of this chapter. You
must follow the requirements described in paragraphs (a)(1) through (8)
of this section to monitor emissions and net energy output at your
affected EGU.
    (1) For each operating hour, calculate the hourly CO2
mass (tons) according to paragraph (a)(4) or (5) of this section,
except that a complete data record is required, i.e., CO2
mass emissions must be reported for each operating hour. Therefore,
substitute data values recorded under part 75 of this chapter for
CO2 concentration, stack gas flow rate, stack gas moisture
content, fuel flow rate and/or gross calorific value (GCV) must be used
in the calculations; and
    (2) Sum all of the hourly CO2 mass emissions values over
the entire compliance period.
    (3) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously measure and record on an hourly basis net electric output.
Measurements must be performed using 0.2 accuracy class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Further, the owner or operator of an
affected EGU that is a combined heat and power facility must install,
calibrate, maintain and operate equipment to continuously measure and
record on an hourly basis useful thermal output and, if applicable,
mechanical output, which are used with net electric output to determine
net energy output (Pnet). The owner or operator must
calculate net energy output according to paragraphs (a)(6)(i)(A) and
(B) of this section.
    (4) The owner or operator of an affected EGU must measure and
report the hourly CO2 mass emissions (lbs) from each
affected unit using the procedures in paragraphs (a)(4)(i) through (vi)
of this section, except as otherwise provided in paragraph (a)(5) of
this section.
    (i) The owner or operator of an affected EGU must install, certify,
operate, maintain, and calibrate a CO2 continuous emissions
monitoring system (CEMS) to directly measure and record CO2
concentrations in the affected EGU 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. However, when an O2
monitor is used this way, it only quantifies the combustion
CO2; therefore, if the EGU is equipped with emission
controls that produce non-combustion CO2 (e.g., from sorbent
injection), then this additional CO2 must be accounted for,
in accordance with section 3 of appendix G to part 75 of this chapter.
As an alternative to direct measurement of CO2
concentration, provided that the affected EGU does not use carbon
separation (e.g., carbon capture and storage), the owner or operator of
an affected EGU may use data from a certified oxygen (O2)
monitor to calculate hourly average CO2 concentrations, in
accordance with Sec.  75.10(a)(3)(iii) of this chapter. If
CO2 concentration is measured on a dry basis, then the owner
or operator of the affected EGU must also install, certify, operate,
maintain, and calibrate a continuous moisture monitoring system,
according to Sec.  75.11(b) of this chapter. Alternatively, the owner
or operator of an affected EGU may either use an appropriate fuel-
specific default moisture value from Sec.  75.11(b) or submit a
petition to the Administrator under Sec.  75.66 of this chapter for a
site-specific default moisture value.
    (ii) Calculate the hourly CO2 mass emission rate (tons/
hr), either from Equation F-11 in Appendix F to part 75 of this chapter
(if CO2 concentration is measured on a wet basis), or by
following the procedure in section 4.2 of Appendix F to part 75 of this
chapter (if CO2 concentration is measured on a dry basis).
CO2 mass emissions must be reported for each operating hour.
Therefore, substitute data values recorded under part 75 of this
chapter for CO2 concentration, stack gas flow rate, stack
gas moisture content, fuel flow rate and/or GCV must be used in the
calculations.
    (iii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in Sec.  72.2
of this chapter), to convert it to tons of CO2. Multiply the
result by 2000 lb/ton to convert it to lb.
    (iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec.  75.57(e) of this chapter and must
be reported electronically under Sec.  75.64(a)(6) of this chapter, if
required by a plan. The owner or operator must use these data, or
equivalent data, to calculate the hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values that
were calculated according to procedures specified in paragraph
(a)(4)(ii) of this section over the entire compliance period.
    (vi) For each continuous monitoring system used to determine the
CO2 mass emissions from an affected EGU, the monitoring
system must meet the applicable certification and quality assurance
procedures in Sec.  75.20 of this chapter and Appendices A and B to
part 75 of this chapter.
    (5) The owner or operator of an affected EGU that exclusively
combusts liquid fuel and/or gaseous fuel may, as an alternative to
complying with paragraph (a)(4) of this section, determine the hourly
CO2 mass emissions according to paragraphs (a)(5)(i) through
(vi) of this section.
    (i) Implement the applicable procedures in appendix D to part 75 of
this chapter to determine hourly EGU 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. The fuel flow
meter(s) used to measure the hourly fuel flow rates must meet the
applicable certification and quality-assurance requirements in sections
2.1.5 and 2.1.6 of appendix D (except for qualifying commercial billing
meters). The fuel GCV must be determined in accordance with section 2.2
or 2.3 of appendix D, as applicable.
    (ii) For each measured hourly heat input rate, use Equation G-4 in
Appendix G to part 75 of this chapter to calculate the hourly
CO2 mass emission rate (tons/hr).
    (iii) Determine the hourly CO2 mass emission rate (tons/
hr) using the procedures specified in paragraph (a)(4)(ii) of this
section and multiply it by the EGU or stack operating time in hours (as
defined in Sec.  72.2 of this chapter), to convert to tons of
CO2. Then, multiply the result by 2000 lb/ton to convert to
lb.
    (iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec.  75.57(e) of this chapter and must
be reported electronically under Sec.  75.64(a)(6), if required by a
plan. You must use these data, or equivalent data, to calculate the
hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values (lb)
that were calculated according to procedures specified in paragraph
(a)(5)(iii) of this

section over the entire compliance period.
    (vi) The owner or operator of an affected EGU 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 may use
these Fc values in the emissions calculations instead of
using the default Fc values in the Equation G-4
nomenclature.
    (6) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously measure and record on an hourly basis net electric output.
Measurements must be performed using 0.2 accuracy class electricity
metering instrumentation and calibration procedures as specified under
ANSI Standards No. C12.20. Further, the owner or operator of an
affected EGU that is a combined heat and power facility must install,
calibrate, maintain and operate equipment to continuously measure and
record on an hourly basis useful thermal output and, if applicable,
mechanical output, which are used with net electric output to determine
net energy output. The owner or operator must calculate net energy
output according to paragraph (a)(6)(i) of this section.
    (i) For each operating hour of a compliance period that was used in
paragraph (a)(4) or (5) of this section to calculate the total
CO2 mass emissions, you must determine Pnet (the
corresponding hourly net energy output in MWh) according to the
procedures in paragraphs (a)(6)(i)(A) and (B) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(4) or (5) of this section, if there is no
gross or net electrical output, but there is mechanical or useful
thermal output, you must still determine the net energy output for that
hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(4) or (5) of this section, but there is no (i.e., zero)
gross electrical, mechanical, or useful thermal output, you must use
that hour in the compliance determination. For hours or partial hours
where the gross electric output is equal to or less than the auxiliary
loads, net electric output must be counted as zero for this
calculation.
    (A) Calculate Pnet for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of megawatt-hours (MWh). To convert each hourly net energy output
value reported under part 75 of this chapter to MWh, multiply by the
corresponding EGU or stack operating time.
[GRAPHIC] [TIFF OMITTED] TP23OC15.016

Where:

Pnet = Net energy output of your affected EGU 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 EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)A = Electric energy used for any auxiliary loads in
MWh.
(Pt)PS = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec.  62.16375, as
applicable) that is used for applications that do not generate
additional electricity, produce mechanical energy output, or enhance
the performance of the affected EGU. This is calculated using the
equation specified in paragraph (a)(6)(i)(B) of this section in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions as defined in Sec.  62.16375, as
applicable) from heat recovery that is used for applications other
than steam generation or performance enhancement of the affected EGU
in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions as defined in Sec.  62.16375, as applicable) from any
integrated equipment that is used for applications that do not
generate additional steam, electricity, produce mechanical energy
output, or enhance the performance of the affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total net energy output consists of
electric or direct mechanical output and 20.0 percent of the total
net energy output consists of useful thermal output on a 12-
operating month rolling average basis, or 1.0 for all other affected
EGUs.

    (B) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.017

Where:

(Pt)ps = Useful thermal output of steam (measured
relative to SATP conditions as defined in Sec.  62.16375, as
applicable) that is used for applications that do not generate
additional electricity, produce mechanical energy output, or enhance
the performance of the affected EGU.
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 SATP conditions as defined in Sec.  62.16375 or the
energy in the condensate return line, as applicable) in Joules per
kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.

    (ii) [Reserved]
    (7) In accordance with Sec.  60.13(g), if two or more affected EGUs
implementing the continuous emissions monitoring provisions in
paragraph (a)(1) of this section share a common exhaust gas stack and
are subject to the same emissions standard, then the owner or operator
may monitor the hourly CO2 mass emissions at the common
stack in lieu of monitoring each EGU separately. If an owner or
operator of an affected EGU chooses this option, then the hourly net
electric output for the common stack must be the sum of the hourly net
electric output of the individual affected facility and the operating
time must be expressed as ``stack operating hours'' (as defined in
Sec.  72.2 of this chapter).
    (8) In accordance with Sec.  60.13(g), if the exhaust gases from an
affected EGU implementing the continuous emissions monitoring
provisions in paragraph (a)(3) 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), the hourly CO2 mass emissions and the ``stack
operating time'' (as defined in Sec.  72.2 of this chapter) at each
stack or duct must be monitored separately. In this case, the owner or
operator of an affected EGU must determine compliance with an
applicable emissions standard by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the net energy output for the affected EGU.

    (b) [Reserved]

Sec.  62.16350  May I bank CO2 annual allowances for future use or
transfer?

    (a) A CO2 allowance may be banked for future use or
transfer in a compliance account or a general account in accordance
with paragraph (b) of this section.
    (b) Any CO2 allowance that is held in a compliance
account or a general account will remain in such account unless and
until the CO2 allowance is deducted or transferred under
Sec. Sec.  62.16240(b), 62.16335, 62.16340, 62.16355, or 62.16370.

Sec.  62.16355  How does the Administrator process account errors?

    The Administrator may, at his or her sole discretion and on his or
her own motion, correct any error in any ATCS account. Within 10
business days of making such correction, the Administrator will notify
the authorized account representative for the account.

Sec.  62.16360  What are my reporting, notification and submission
requirements?

    (a) You must prepare and submit reports according to paragraphs (a)
through (e) of this section, as applicable.
    (1) You must meet all applicable reporting requirements and submit
reports as required under subpart G of part 75 of this chapter and you
must include the following information, as applicable in the quarterly
reports:
    (i) The hourly CO2 mass emission rate value (tons/hr)
and unit (or stack) operating time, as monitored and reported according
to part 75 of this chapter, for each unit or stack operating hour in
the compliance period;
    (ii) The calculated CO2 mass emissions (tons) for each
unit or stack operating hour in the compliance period;
    (iii) The sum of the CO2 mass emissions (tons) for all
of the unit or stack operating hours in the compliance period;
    (iv) The net electric output and the net energy output
(Pnet) values for each unit or stack operating hour in the
compliance period;
    (v) The sum of the hourly net energy output values for all of the
unit or stack operating hours in the compliance period; and
    (vi) If the report covers the final quarter of a compliance period,
then you must include the CO2 emission standard with which
your affected EGU must comply, the affected EGU's calculated emission
performance as a cumulative mass in units of the emission standard
required, and if an affected EGU is complying with an emission standard
by using allowances, then the designated representative must include in
their report a list of all unique allowance serial numbers retired in
the compliance period, and, for each allowance, the date an allowance
was surrendered and retired. If set-aside allowances were used from an
eligible resource by an affected EGU to comply with its emission
standard, then the designated representative must include in their
report the eligible resource identification information sufficient to
demonstrate that it meets the requirements of Sec.  62.16245 and
qualifies to be issued allowance set-asides (including location, type
of qualifying generation or savings, date commenced generating or
saving, and date of generation or savings for which the allowance was
issued).
    (2) [Reserved]
    (b) The designated representative of each affected EGU at the
facility must make all submissions required under the CO2
Mass-based Trading Program, except as provided in Sec.  62.16315. This
requirement does not change, create an exemption from, or otherwise
affect the responsible official submission requirements under a title V
operating permit program in parts 70 and 71 of this chapter.
    (c) 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.
    (d) For affected EGUs under this subpart that are not in the Acid
Rain Program, you must also meet the reporting requirements and submit
reports as required under subpart G of part 75 of this chapter, to the
extent that those requirements and reports provide applicable data for
the compliance demonstrations required under this subpart.
    (e) If your affected EGU captures CO2 to meet the
applicable emission standard, then you must report in accordance with
the requirements of 40 CFR part 98, subpart PP, of this chapter and
either:
    (1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, of this chapter, if injection occurs on-site; or
    (2) Transfer the captured CO2 to an EGU or facility that
reports in accordance with the requirements of 40 CFR part 98, subpart
RR, of this chapter, if injection occurs off site.
    (f) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable to your affected EGUs.

Sec.  62.16365  What are my recordkeeping requirements?

    (a) The owner or operator of each affected EGU must maintain the
records, as described in paragraphs (a)(1) and (2) of this section, for
at least 5 years following the date of each compliance period,
occurrence, measurement, maintenance, corrective action, report, or
record.
    (1) The owner or operator of an affected EGU must maintain each
record on site for at least 2 years after the date of each compliance
period, compliance true-up period, occurrence, measurement,
maintenance, corrective action, report, or record, whichever is latest,
according to Sec.  60.7 of this chapter. The owner or operator of an
affected EGU may maintain the records off site and electronically for
the remaining year(s).
    (2) The owner or operator of an affected EGU must keep all of the
following records:
    (i) All emissions monitoring information, in accordance with this
subpart;
    (ii) Copies of all reports, compliance certifications, documents,
data files, calculations and methods, other submissions and all records
made or required under, or to demonstrate compliance with an affected
EGU's emission standard under Sec.  62.16220 and any other requirements
of, the CO2 Mass-based Trading Program;
    (iii) Data that is required to be recorded by 40 CFR part 75,
subpart F, of this chapter; and
    (iv) Data with respect to any allowances used by the affected EGU
in its compliance demonstration including the information in paragraphs
(a)(2)(iv)(A) and (B) of this section.
    (A) All documents related to any set-aside allowances used in a
compliance demonstration, including each eligibility application, EM&V
plan, M&V report, and independent verifier verification report
associated with the issuance of each specific set-aside allowance, and
each regulatory approval and any documentation that supports the
issuance of each set-aside allowance by the Administrator.
    (B) All records and reports relating to the surrender and
retirement of allowances for compliance with this regulation, including
the date each individual allowance with a unique serial identification
number was surrendered and/or retired.
    (b) [Reserved]

Sec.  62.16370  What actions may the Administrator take on submissions?

    (a) The Administrator may review and conduct independent audits
concerning

any submission under the CO2 Mass-based Trading Program and
make appropriate adjustments of the information in the submission.
    (b) The Administrator may deduct CO2 allowances from or
transfer CO2 allowances to a compliance account, based on
the information in a submission, as adjusted under paragraph (a) of
this section, and record such deductions and transfers.

Definitions

Sec.  62.16375  What definitions apply to this subpart?

    The terms used in this subpart have the meanings set forth in this
section as follows:
    Acid Rain Program means a multi-state SO2 and
NOX air pollution control and emission reduction program
established by the Administrator under title IV of the Clean Air Act
and parts 72 through 78 of this chapter.
    Administrator means the Administrator of the United States
Environmental Protection Agency or his or her delegate, or the
authorized state official under an approved state plan that
incorporates this subpart.
    Affected electric generating unit or Affected EGU means any steam
generating unit, IGCC, or stationary combustion turbine that meets the
applicability requirements in Sec. Sec.  60.5840(b) and 60.5845 of this
chapter. An affected EGU is not an eligible resource.
    Allocate or allocation means, with regard to CO2
allowances, the determination by the Administrator, State, or
permitting authority, in accordance with this subpart or any state
allowance-distribution methodology submitted by the State and approved
by the Administrator under Sec.  62.16245, to:
    (1) An affected EGU;
    (2) A renewable energy set-aside;
    (3) An output-based set-aside; or
    (4) Any other entity specified by the Administrator.
    Allowable CO2 emission rate means, for an affected EGU,
the most stringent state or federal CO2 emission rate limit
(in lb/MWh or, if in lb/mmBtu, converted to lb/MWh by multiplying it by
the affected EGU's heat rate in mmBtu/MWh) that is applicable to the
affected EGU and covers the longest averaging period not exceeding 1
year.
    Allowance system means a control program under which the owner or
operator of each affected EGU is required to hold an authorization for
each specified unit of carbon dioxide emitted from that facility during
a specified period and which limits the total amount of such
authorizations available to be held for carbon dioxide for a specified
period and allows the transfer of such authorizations not used to meet
the authorization-holding requirement.
    Allowance Tracking and Compliance System (ATCS) means the system by
which the Administrator records allocations, deductions, and transfers
of CO2 allowances under the CO2 Mass-based
Trading Program. Such allowances are allocated, recorded, held,
deducted, or transferred only as whole allowances.
    Allowance transfer deadline means, for a compliance period in a
given year, midnight of May 1 (if it is a business day), or midnight of
the first business day thereafter (if May 1 is not a business day),
immediately after such compliance period and is the deadline by which a
CO2 allowance transfer must be submitted for recordation in
a facility's compliance account in order to be available for use in
complying with the facility's CO2 emission standard for such
compliance period in accordance with Sec. Sec.  62.16220 and 62.16340.
    Alternate designated representative means, for a CO2
Mass-based Trading Program facility and each affected EGU at the
facility, the natural person who is authorized by the owners and
operators of the facility and all such affected EGUs at the facility,
in accordance with this subpart, to act on behalf of the designated
representative in matters pertaining to the CO2 Mass-based
Trading Program. If the facility is also subject to the Acid Rain
Program, TR NOX Annual Trading Program, TR NOX
Ozone Season Trading Program, TR SO2 Group 1 Trading
Program, or TR SO2 Group 2 Trading Program, then this
natural person shall be the same natural person as the alternate
designated representative, as defined in the respective program.
    Annual capacity factor means the ratio between the actual heat
input to an affected EGU during a calendar year and the potential heat
input to the affected EGU had it been operated for 8,760 hours during a
calendar year at the base load rating. Also see capacity factor.
    Authorized account representative means, for a general account, the
natural person who is authorized, in accordance with this subpart, to
transfer and otherwise dispose of CO2 allowances held in the
general account and, for a CO2 Mass-based Trading facility's
compliance account, the designated representative of the facility is
the authorized account representative.
    Automated data acquisition and handling system (DAHS) means the
component of the continuous emission monitoring system, or other
emissions monitoring system approved for use under this subpart,
designed to interpret and convert individual output signals from
pollutant concentration monitors, flow monitors, diluent gas monitors,
and other component parts of the monitoring system to produce a
continuous record of the measured parameters in the measurement units
required by this subpart.
    Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
    Baseline means the electricity use that would have occurred without
implementation of a specific EE measure.
    Biomass means biologically based material that is living or dead
(e.g., trees, crops, grasses, tree litter, roots) above and below
ground, and available on a renewable or recurring basis. Materials that
are biologically based include non-fossilized, biodegradable organic
material originating from modern or contemporarily grown plants,
animals, or microorganisms (including plants, products, byproducts and
residues from agriculture, forestry, and related activities and
industries, as well as the non-fossilized and biodegradable organic
fractions of industrial and municipal wastes, including gases and
liquids recovered from the decomposition of non-fossilized and
biodegradable organic material).
    Boiler means an enclosed fossil- or other-fuel-fired combustion
device used to produce heat and to transfer heat to recirculating
water, steam, or other medium.
    Business day means a day that does not fall on a weekend or a
federal holiday.
    Capacity factor means, as used for the output based set-aside, the
ratio of the net electrical energy produced by a generating unit for
the period of time considered to the electrical energy that could have
been produced at continuous net summer capacity during the same period.
    Certifying official means a natural person who is:
    (1) For a corporation, a president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business function
or any other person who performs similar policy- or decision-making
functions for the corporation;

    (2) For a partnership or sole proprietorship, a general partner or
the proprietor respectively; or
    (3) For a local government entity or state, federal, or other
public agency, a principal executive officer or ranking elected
official.
    Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
    CO2 allowance means a limited authorization issued and
allocated by the Administrator under this subpart, or by a State or
permitting authority under a state allowance-distribution methodology
approved by the Administrator under Sec.  60.24(x) of this chapter, to
emit one ton of CO2 during a compliance period of the
specified calendar year for which the authorization is allocated or of
any calendar year thereafter under the CO2 Mass-Based
Trading Program.
    CO2 allowance deduction or deduct CO2
allowances means the permanent withdrawal of CO2 allowances
by the Administrator from a compliance account (e.g., in order to
account for compliance with the CO2 emission standard).
    CO2 allowances held or hold CO2 allowances
means the CO2 allowances treated as included in an Allowance
Tracking and Compliance System (ATCS) account as of a specified point
in time because at that time they:
    (1) Have been recorded by the Administrator in the account or
transferred into the account by a correctly submitted, but not yet
recorded, CO2 allowance transfer in accordance with this
subpart; and
    (2) Have not been transferred out of the account by a correctly
submitted, but not yet recorded, CO2 allowance transfer in
accordance with this subpart.
    CO2 emission goal means a statewide rate-based
CO2 emission goal or mass-based CO2 emission goal
specified in Sec.  62.16235.
    CO2 emissions limitation means the tonnage of
CO2 emissions authorized in a compliance period in a given
year by the CO2 allowances available for deduction for the
facility under Sec.  62.16340(a) for such compliance period.
    CO2 Mass-Based Trading Program means a multi-state
CO2 air pollution control and emission reduction program
established in accordance with this subpart and subpart UUUU of part 60
of this chapter (including such a program that is revised in a State
plan or state allowance distribution methodology, or by the
Administrator under subpart UUUU of part 60 of this chapter), as a
means of controlling CO2 emissions.
    Coal means the definition as defined in subpart TTTT of part 60 of
this chapter.
    Combined cycle unit 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 unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously
produce both electric (or mechanical) and useful thermal output from
the same primary energy facility.
    Common practice baseline (CPB) means a baseline derived based on a
default technology or condition that would have been in place at the
time of implementation of an EE measure in the absence of the EE
measure (for example, the standard or market-average or pre-existing
equipment that a typical consumer/building owner would have continued
to use or would have installed at the time of project implementation in
a given circumstance, such as a given building type, EE program type or
delivery mechanism, and geographic region).
    Common stack means a single flue through which emissions from two
or more units are exhausted.
    Compliance account means an ATCS account, established by the
Administrator for a CO2 annual facility under this subpart,
in which any CO2 allowance allocations to the affected EGUs
at the facility are recorded and in which are held any CO2
allowances available for use for a compliance period in a given year in
complying with the facility's CO2 emission standard in
accordance with Sec. Sec.  62.16220 and 62.16340.
    Compliance period means the multi-year periods starting January 1
of the first calendar year of the period, except as provided in Sec.
62.16220(c)(3), and ending on December 31 of the last calendar year,
inclusive:
    (1) Compliance Period 1 means the period of 3 calendar years from
January 1, 2022 to December 31, 2024.
    (2) Compliance Period 2 means the period of 3 calendar years from
January 1, 2025 to December 31, 2027.
    (3) Compliance Period 3 means the period of 2 calendar years from
January 1, 2028 to December 31, 2029.
    Conservation voltage regulation (or reduction) (CVR) means an EE
measure that produces electricity savings by reducing (or regulating)
voltage at the electrical feeder level.
    Continuous emission monitoring system (CEMS) means the equipment
required under this subpart to sample, analyze, measure, and provide,
by means of readings recorded at least once every 15 minutes and using
an automated data acquisition and handling system (DAHS), a permanent
record of CO2 emissions, stack gas volumetric flow rate,
stack gas moisture content, and O2 concentration (as
applicable), in a manner consistent with part 75 of this chapter and
Sec.  62.16345. The following systems are the principal types of
continuous emission monitoring systems:
    (1) A flow monitoring system, consisting of a stack flow rate
monitor and an automated data acquisition and handling system and
providing a permanent, continuous record of stack gas volumetric flow;
    (2) A moisture monitoring system, as defined in Sec.  75.11(b)(2)
of this chapter and providing a permanent, continuous record of the
stack gas moisture content, in percent H2O;
    (3) A CO2 monitoring system, consisting of a
CO2 pollutant concentration monitor (or an O2
monitor plus suitable mathematical equations from which the
CO2 concentration is derived) and an automated data
acquisition and handling system and providing a permanent, continuous
record of CO2 emissions, in percent CO2; and
    (4) An O2 monitoring system, consisting of an
O2 concentration monitor and an automated data acquisition
and handling system and providing a permanent, continuous record of
O2, in percent O2.
    Control area operator means an electric system or systems, bounded
by interconnection metering and telemetry, capable of controlling
generation to maintain its interchange schedule with other control
areas and contributing to frequency regulation of the interconnection.
    Deemed savings means estimates of average annual electricity
savings for a single unit of an installed demand-side EE measure that:
Has been developed from data sources (such as prior metering studies)
and analytical methods widely considered acceptable for the measure;
and is applicable to the situation and conditions in which the measure
is implemented. Individual parameters or calculation methods also can
be deemed, including EUL values. Common sources of deemed savings
values are previous evaluations and studies that involved actual
measurements and analyses. Deemed savings values are applicable for
specific demand-side EE measures. A

single deemed savings value may not be used for a program as a whole,
nor for a multi-measure project, because of the degree of variation in
how systems are used in different building types or market segments.
    Demand-side energy efficiency or demand-side EE means energy
efficiency activities, projects, programs or measures resulting in
electricity savings.
    Derate means a decrease in the available capacity of an electric
generating unit, due to a system or equipment modification or to
discounting a portion of a generating unit's capacity for planning
purposes.
    Designated representative means, for a CO2 Mass-based
Trading facility and each affected EGU at the facility, the natural
person who is authorized by the owners and operators of the facility
and all such affected EGUs at the facility, in accordance with this
subpart, to represent and legally bind each owner and operator in
matters pertaining to the CO2 Mass-based Trading Program. If
the CO2 Mass-based Trading facility is also subject to the
Acid Rain Program, TR NOX Annual Trading Program, TR
NOX Ozone Season Trading Program, TR SO2 Group 1
Trading Program, or TR SO2 Group 2 Trading Program, then
this natural person shall be the same natural person as the designated
representative, as defined in the respective program.
    Design efficiency means the rated overall net efficiency (e.g.,
electric plus thermal output) on a higher heating value basis of the
EGU at the base load rating and ISO conditions.
    Distillate oil means the definition as defined in subpart TTTT of
part 60 of this chapter.
    Effective useful life (EUL) means the duration over which
electricity savings from an EE measure occur, reported in years. EUL
values are typically specific to individual EE projects but also may be
specified by EE program.
    Energy efficiency measure or EE measure means a single technology,
energy-use practice or behavior that, once implemented or adopted,
reduces electricity use of a particular end-use, facility, or premises;
EE measures may be implemented as part of an EE program or as an
independent privately-funded action.
    Energy efficiency program or EE program means organized activities
sponsored and funded by a particular entity to promote the adoption of
one or more EE project or EE measure for the purpose of reducing
electricity use.
    Energy efficiency project or EE project means a combination of
multiple technologies, energy-use practices or behaviors implemented at
a single facility or premises for the purpose of reducing electricity
use; EE projects may be implemented as part of an EE program or as an
independent privately-funded action.
    Electricity savings means the savings that results from a change in
electricity use resulting from the implementation of an EE measure.
    Eligible resource means a resource that meets the requirements of
Sec.  62.16245 and has been registered with the EPA-administered ATCS
or an allowance tracking system approved in a State plan by the EPA. An
eligible resource is not an affected EGU.
    EM&V plan means an evaluation measurement and verification plan
that meets the requirements of Sec.  62.16260.
    Emissions means air pollutants exhausted from an affected EGU or
facility into the atmosphere; emissions must be measured, recorded, and
reported to the Administrator by the designated representative, and as
modified by the Administrator:
    (1) In accordance with this subpart; and
    (2) With regard to a period before the affected EGU or facility is
required to measure, record, and report such air pollutants in
accordance with this subpart, and in accordance with part 75 of this
chapter.
    Emission rate credit (ERC) means a tradable compliance instrument
that meets the requirements of Sec.  60.5790(c) of this chapter.
    Energy service company means a private enterprise engaged in
delivering electricity savings directly for an end-use customer or as
an agent of a sponsoring entity such as a utility.
    Essential generating characteristics means any characteristic that
affects the eligibility of the qualifying energy generating facility
for generating allowances pursuant to this regulation, including the
type of facility.
    Excess emissions means any ton of emissions from the affected EGUs
at a facility during a compliance period that exceeds the
CO2 emissions limitation for the facility for such
compliance period.
    Existing state program, requirement, or measure means, in the
context of a State plan, a regulation, requirement, program, or measure
administered by a state, utility, or other entity that is currently
established. This may include a regulation or other legal requirement
that includes past, current, and future obligations, or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future, in accordance with established
plans. An existing state program, requirement, or measure may have
past, current, and future impacts on EGU CO2 emissions.
    Facility means all buildings, structures, or installations located
in one or more contiguous or adjacent properties under common control
of the same person or persons. This definition does not change or
otherwise affect the definition of ``major source'', ``stationary
source'', or ``source'' as set forth and implemented in a title V
operating permit program or any other program under the Clean Air Act.
    Final compliance period means a compliance period within the final
period, each being 2 calendar years (with a calendar year beginning on
January 1 and ending on December 31), and the first final compliance
period beginning on January 1, 2030 and ending December 31, 2031.
    Final period means the period that begins on January 1, 2030 and
continues thereafter. The final period is comprised of final compliance
periods, each of which is 2 calendar years (with a calendar year
beginning on January 1 and ending on December 31).
    Fossil fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
    Fossil-fuel-fired means, with regard to an affected EGU, combusting
any amount of fossil fuel.
    Gaseous fuel means the definition as defined in subpart TTTT of
part 60 of this chapter.
    General account means an ATCS account established under this
subpart that is not a compliance account.
    Generation period means the compliance period from which the
Administrator uses operations data of affected EGUs to calculate
allowances from the output-based allocation set-aside for the following
compliance period.
    Generation year means a calendar year for which a renewable energy
project submits its projected generation to the Administrator by June 1
of the preceding year for allowances from the renewable energy set-
aside.
    Generator means a device that produces electricity.
    Gross electrical output means, for an affected EGU, electricity
made available for use, including any such electricity used in the
power production process (which process includes, but is not limited
to, any on-site processing or treatment of fuel combusted at the
affected EGU and any on-site emission controls).
    Heat input means, for an affected EGU for a specified period of
time, the product (in mmBtu/time) of the gross calorific value of the
fuel (in mmBtu/lb) fed into the affected EGU multiplied by

the fuel feed rate (in lb of fuel/time), as measured, recorded, and
reported to the Administrator by the designated representative and as
modified by the Administrator in accordance with this subpart and
excluding the heat derived from preheated combustion air, recirculated
flue gases, or exhaust.
    Heat input rate means, for an affected EGU, the amount of heat
input (in mmBtu) divided by affected EGU operating time (in hr) or, for
an affected EGU and a specific fuel, the amount of heat input
attributed to the fuel (in mmBtu) divided by the affected EGU operating
time (in hr) during which the affected EGU combusts the fuel.
    Heat rate means, for an affected EGU, the affected EGU's maximum
design heat input (in Btu/hr), divided by the product of 1,000,000 Btu/
mmBtu and the affected EGU's maximum hourly load.
    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.
    Indian country means ``Indian country'' as defined in 18 U.S.C.
1151.
    Integrated gasification combined cycle facility or IGCC facility
means a combined cycle facility that is designed to burn fuels
containing 50 percent (by heat input) or more solid-derived fuel not
meeting the definition of natural gas plus any integrated equipment
that provides electricity or useful thermal output to either the
affected facility or auxiliary equipment. 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.
    Interim period means the period of 8 calendar years from January 1,
2022 to December 31, 2029. The interim period is comprised of three
compliance periods, compliance period 1, compliance period 2, and
compliance period 3.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
    Liquid fuel means the definition as defined in subpart TTTT of part
60 of this chapter.
    M&V report means a monitoring and verification report that meets
the requirements of Sec.  62.16265.
    Maximum design heat input means, for an affected EGU, the maximum
amount of fuel per hour (in Btu/hr) that the affected EGU is capable of
combusting on a steady state basis as of the initial installation of
the affected EGU as specified by the manufacturer of the affected EGU.
    Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, 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.
    Monitoring system means any monitoring system that meets the
requirements of this subpart, including a continuous emission
monitoring system, an alternative monitoring system, or an excepted
monitoring system under part 75 of this chapter.
    Nameplate capacity means, starting from the initial installation of
a generator, the maximum electrical generating output (in MWe, rounded
to the nearest tenth) that the generator is capable of producing on a
steady state basis and during continuous operation (when not restricted
by seasonal or other deratings) of such installation as specified by
the manufacturer of the generator or, starting from the completion of
any subsequent physical change in the generator resulting in an
increase in the maximum electrical generating output that the generator
is capable of producing on a steady state basis and during continuous
operation (when not restricted by seasonal or other deratings), such
increased maximum amount (in MWe, rounded to the nearest tenth) of such
completion as specified by the person conducting the physical change.
    Natural gas means the definition as defined in subpart TTTT of part
60 of this chapter.
    Net-electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
    Net energy output means:
    (1) The net electric or mechanical output from the affected
facility, plus 100 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the
affected EGU (e.g., steam delivered to an industrial process for a
heating application); and
    (2) For combined heat and power facilities where at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output and at least 20.0 percent of the total gross
or net energy output consists of useful thermal output on a 12-
operating month rolling average basis, the net electric or mechanical
output from the affected EGU divided by 0.95, plus 100 percent of the
useful thermal output (e.g., steam delivered to an industrial process
for a heating application).
    Net summer capacity means the maximum output, commonly expressed in
megawatts (MW), that generating equipment can supply to system load, as
demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30.) This output reflects a
reduction in capacity due to electricity use for station service or
auxiliaries.
    Operate or operation means, with regard to an affected EGU, to
combust fuel.
    Operator means, for a CO2 Mass-based Trading facility or
an affected EGU at a facility respectively, any person who operates,
controls, or supervises an affected EGU at the facility or the affected
EGU and includes, but is not limited to, any holding company, utility
system, or plant manager of such facility or affected EGU.
    Owner means, for a CO2 Mass-based Trading facility or an
affected EGU at a facility respectively, any of the following persons:
    (1) Any holder of any portion of the legal or equitable title in an
affected EGU at the facility or the affected EGU;
    (2) Any holder of a leasehold interest in an affected EGU at the
facility or the affected EGU, provided that, unless expressly provided
for in a leasehold agreement, ``owner'' does not include a passive
lessor, or a person who has an equitable interest through such lessor,
whose rental payments are not based (either directly or indirectly) on
the revenues or income from such affected EGU; and
    (3) Any purchaser of power from an affected EGU at the facility or
the affected EGU under a life-of-the-unit, firm power contractual
arrangement.
    Permanently retired means, with regard to an affected EGU, that an
affected EGU is unavailable for service and the affected EGU's owners
and operators: have taken on as enforceable obligations in the
operating permit that covers the affected EGU the conditions of Sec.
62.16215; or rescinded or otherwise

terminated all permits required for construction or operation of the
affected EGU under the Clean Air Act. Cessations in operations that do
not meet this definition do not constitute permanent retirements.
    Qualified biomass means a biomass feedstock that is demonstrated as
a method to control increases of CO2 levels in the
atmosphere.
    Random error means errors occurring by chance that may cause
electricity savings values to be inconsistently overestimated or
underestimated, and may result from a change in electricity use due to
unaccounted-for factors that affect electricity use. The magnitude of
random error can be quantified based on the variations observed across
different units.
    Receive or receipt of means, when referring to the Administrator,
to come into possession of a document, information, or correspondence
(whether sent in hard copy or by authorized electronic transmission),
as indicated in an official log, or by a notation made on the document,
information, or correspondence, by the Administrator in the regular
course of business.
    Recordation, record, or recorded means, with regard to
CO2 allowances, the moving of CO2 allowances by
the Administrator into, out of, or between ATCS accounts, for purposes
of allocation, transfer, or deduction.
    Reference method means any direct test method of sampling and
analyzing for an air pollutant as specified in Sec.  75.22 of this
chapter.
    Replacement, replace, or replaced means, with regard to an affected
EGU, the demolishing of an affected EGU, or the permanent retirement
and permanent disabling of an affected EGU, and the construction of
another affected EGU (the replacement affected EGU) to be used instead
of the demolished or retired affected EGU (the replaced affected EGU).
    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.
    Solid waste incineration unit means a stationary, fossil-fuel-fired
boiler or stationary, fossil-fuel-fired combustion turbine that is a
``solid waste incineration unit'' as defined in section 129(g)(1) of
the Clean Air Act.
    Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25[deg] C, 77 [deg]F)) and 100.0 kilopascals (14.504
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is
50 Btu/lb.
    State agent means an entity acting on behalf of the State, with the
legal authority of the State.
    State measures means measures that the State adopts and implements
as a matter of state law. Such measures are enforceable only per state
law, and are not included in and codified as part of the federally
enforceable State plan.
    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 emissions 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 then 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.
    Submit or serve means to send or transmit a document, information,
or correspondence to the person specified in accordance with the
applicable regulation:
    (1) In person;
    (2) By United States Postal Service; or
    (3) By other means of dispatch or transmission and delivery;
    (4) Provided that compliance with any ``submission'' or ``service''
deadline shall be determined by the date of dispatch, transmission, or
mailing and not the date of receipt.
    Systematic error means inaccuracies in the same direction, causing
electricity savings values to be consistently either overestimated or
underestimated, and may result from factors such as incorrect
assumptions, a methodological issue, or a flawed reporting system.
    Transmission and distribution loss means the difference between the
quantity of electricity that serves a load (measured at the busbar of
the generator) and the actual electricity use at the final distribution
location (measured at the on-site meter).
    Transmission and distribution measures or T&D measures means EE
measures intended to improve the efficiency of the electrical
transmission and distribution system by decreasing electricity loses on
the system.
    Unit operating day means, with regard to an affected EGU, a
calendar day in which the affected EGU combusts any fuel.
    Unit operating hour or hour of unit operation means, with regard to
an affected EGU, an hour in which the affected EGU combusts any fuel.
    Uprate means an increase in available electric generating unit
power capacity due to a system or equipment modification.
    Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
    Utility power distribution system means the portion of an
electricity grid owned or operated by a utility and dedicated to
delivering electricity to customers.
    Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in Sec.  75.20 of this chapter and appendix
A to part 75 of this chapter must be met before quality-assured data
are reported under this subpart; for on-going quality

assurance, the daily, quarterly, and semiannual/annual test
requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of
this chapter must be met and the data validation criteria in sections
2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply.
For fuel flow meters, the initial certification requirements in section
2.1.5 of appendix D to part 75 of this chapter must be met before
quality-assured data are reported under this subpart (except for
qualifying commercial billing meters under section <IP_ADDRESS> of appendix
D), and for on-going quality assurance, the provisions in section 2.1.6
of appendix D to part 75 of this chapter apply (except for qualifying
commercial billing meters).
    Verification report means a report that meets the requirements of
Sec.  62.16270.
    Waste-to-Energy means a process or unit (e.g., solid waste
incineration unit) that recovers energy from the conversion or
combustion of waste stream materials, such as municipal solid waste, to
generate electricity and/or heat.

Sec.  62.16380  What measurements, abbreviations, and acronyms apply to
this subpart?

    The measurements, abbreviations, and acronyms used in this subpart
are defined as follows:

ADR--alternated designated representative
Btu--British thermal unit
CO2--carbon dioxide
COI--conflict of interest
CPP--clean power plan
CVR--conservation voltage regulation
DR--designated representative
EE--energy efficiency
EGU--electric generating unit
EM&V--evaluation, measurement, and verification
GCV--gross calorific value
GJ--giga joule
H2O--water
hr--hour
IGCC--integrated gasification combined cycle
kg--kilogram
kW--kilowatt electrical
kWh--kilowatt hour
lb--pound
M&V--measurement and verification
mmBtu--million Btu
MWe--megawatt electrical
MWh--megawatt hour
O2--oxygen
PB-MV--project-based measurement and verification
PSD--prevention of significant deterioration
T&D--transmission and distribution
TRM--technical reference manual
yr--year

0
5. Add subpart NNN to read as follows:

Subpart NNN--Greenhouse Gas Emissions Rate-based Model Trading Rule
for Electric Utility Generating Units That Commenced Construction
on or Before January 8, 2014

Sec.

Introduction

62.16405 What is the purpose of this subpart?

Applicability of This Subpart

62.16410 Am I subject to this subpart?
62.16415 What are the requirements for retired affected EGUs?

General Requirements

62.16420 What emission standards and requirements must I comply
with?
62.16425 How should I compute time under the CO2 Rate-
based Trading Program?
62.16430 What are the administrative appeal procedures?
62.16431 How will the Clean Energy Incentive Program be administered
under the federal plan?

Emission Rate Credit Issuance, Adjustment, and Revocation

62.16434 What affected EGUs qualify for generation of ERCs?
62.16435 What eligible resources qualify for generation of ERCs in
addition to affected EGUs?
62.16440 What is the process for revocation of qualification status
of an eligible resource?
62.16445 What is the process for the issuance of ERCs?
62.16450 What is the process for error adjustments or misstatement,
and suspension of ERC issuance?

Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification

62.16455 What are the requirements for evaluation measurement and
verification plans for eligible resources?
62.16460 What are the requirements for monitoring and verification
reports for eligible resources?
62.16465 What are the requirements for verification reports?
62.16470 What is the accreditation procedure for independent
verifiers?
62.16475 What are the procedures of accredited independent verifiers
must follow to avoid conflict of interest?
62.16480 What is the process for the revocation of accreditation
status for an independent verifier?

Designated Representatives

62.16485 How are designated representatives and alternate designated
representatives authorized and what role do authorized designated
representatives and alternate designated representatives play?
62.16490 What responsibilities do designated representatives and
alternate designated representatives hold?
62.16495 What are the processes for changing designated
representatives, alternate designated representatives, owners and
operators, and affected EGUs?
62.16500 What must be included in a certificate of representation?
62.16505 What is the Administrator's role in objections concerning
designated representatives and alternate designated representatives?
62.16510 What process must designated representatives and alternate
designated representatives follow to delegate their authority?

Monitoring, Recordkeeping, Reporting

62.16515 How are compliance accounts and general accounts
established and used, and how is ERC issuance documentation
accessed?
62.16525 How must transfers of ERCs be submitted?
62.16530 When will ERC transfers be recorded?
62.16535 How will deductions for compliance with a CO2
emission standard occur?
62.16540 What monitoring requirements must I comply with?
62.16545 May I bank CO2 ERCs for future use or transfer?
62.16550 How does the Administrator process account errors?
62.16555 What are my reporting, notification and submission
requirements?
62.16560 What are my recordkeeping requirements?
62.16565 What actions may the Administrator take on submissions?

Definitions

62.16570 What definitions apply to this subpart?
62.16575 What measurements, abbreviations, and acronyms apply to
this subpart?
Table 1 to Subpart NNN of Part 62--CO2 Emission Standards
(Pounds of CO2 Per Net MWh)
Table 2 to Subpart NNN of Part 62--Incremental Generation Factor for
Emission Rate Credits

Subpart NNN--Greenhouse Gas Emissions Rate-Based Model Trading Rule
for Electric Utility Generating Units That Commenced Construction
on or Before January 8, 2014

Introduction

Sec.  62.16405  What is the purpose of this subpart?

    (a) This subpart sets forth the requirements for the Clean Power
Plan (CPP) CO2 Rate-based Trading Program, under section 111
of the Clean Air Act and subpart UUUU of part 60 of this chapter, as a
means of meeting emission guidelines limiting greenhouse gas emissions
from an affected steam generating unit, integrated gasification
combined cycle (IGCC), or stationary combustion turbine.

    (b) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas limitations in this subpart are in the form of an
emission standard for carbon dioxide (CO2).
    (c) PSD and Title V thresholds for greenhouse gases. (1) For the
purposes of Sec.  51.166(b)(49)(ii) of this chapter, 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 Sec.  51.166(b)(48) of this chapter and in
any state implementation plan approved by the EPA that is interpreted
to incorporate, or specifically incorporates, Sec.  51.166(b)(48) of
this chapter.
    (2) For the purposes of Sec.  52.21(b)(50)(ii) of this chapter,
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 Sec.  52.21(b)(49) of this
chapter.
    (3) For the purposes of Sec.  70.2 of this chapter, 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 Sec.  70.2 of this chapter.
    (4) For the purposes of Sec.  71.2 of this chapter, 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 Sec.  71.2 of this chapter.

Applicability of This Subpart

Sec.  62.16410  Am I subject to this subpart?

    (a) You are subject to this subpart if you are the owner or
operator of an affected electric generating unit (EGU) located within a
State that has incorporated by reference this subpart as a State plan,
or portion of a State plan, that has been approved by the Administrator
and is effective under subpart UUUU of part 60 of this chapter, or if
this subpart is promulgated and effective as a federal plan in your
State under part 62 of this chapter.
    (b) An affected EGU is any steam generating unit, IGCC, or
stationary combustion turbine that meets the applicability requirements
in Sec. Sec.  60.5840(b) and 60.5845 of this chapter.

Sec.  62.16415  What are the requirements for retired affected EGUs?

    (a) Exemption. (1) Any affected EGU that is permanently retired as
defined in Sec.  62.16570 is exempt from Sec. Sec.  62.16420(c)(1)
[CO2 Emissions Requirements], 62.16535 [Compliance
Requirements], 62.16540 [Monitoring], 62.16555 [Reporting], and
62.16560 [Recordkeeping].
    (2) The exemption under paragraph (a)(1) of this section will
become effective on the first day of the compliance period immediately
following the compliance period in which the retirement took effect.
Within 30 days of the affected EGU's permanent retirement, the
designated representative must submit a statement to the Administrator.
The statement must state, in a format prescribed by the Administrator,
that the affected EGU was permanently retired on a specified date and
will comply with the requirements of paragraph (b) of this section.
    (b) Special provisions. (1) An affected EGU exempt under paragraph
(a) of this section must not emit any CO2, starting on the
date that the exemption takes effect.
    (2) For a period of 5 years from the date the records are created,
the owners and operators of an affected EGU exempt under paragraph (a)
of this section must retain, at the affected EGU, records demonstrating
that the affected EGU is permanently retired. The 5-year period for
keeping records may be extended for cause, at any time before the end
of the period, in writing by the Administrator. The owners and
operators bear the burden of proof that the affected EGU is permanently
retired.
    (3) The owners and operators and, to the extent applicable, the
designated representative of an affected EGU exempt under paragraph (a)
of this section must comply with the requirements of the CO2
Rate-based Trading Program accruing during any compliance periods for
which the exemption is not in effect, even if such requirements must be
complied with after the exemption takes effect.

General Requirements

Sec.  62.16420  What emission standards and requirements must I comply
with?

    (a) Designated representative requirements. The owners and
operators must have a designated representative, and may have an
alternate designated representative, in accordance with Sec. Sec.
62.16485 through 62.16495.
    (b) Emissions monitoring, reporting, and recordkeeping
requirements. (1) The owners and operators, and the designated
representative, of affected EGU must comply with the monitoring,
reporting, and recordkeeping requirements of Sec. Sec.  62.16540,
62.16555, and 62.16560.
    (2) The emissions data determined in accordance with Sec.  62.16540
must be used to determine compliance with the CO2 emission
standard under paragraph (c) of this section, provided that, for each
monitoring location from which emissions are reported, the emission
rate used in determining compliance must be the CO2 emission
rate at the monitoring location determined in accordance with paragraph
(c) of this section.
    (c) CO2 emission standard requirements. (1) Each designated
representative for each affected EGU must demonstrate compliance with
its emission standard listed in Table 1 of this subpart, as applicable,
by calculating a CO2 emission rate by factoring stack
emissions and any emission rate credits (ERCs) into the following
equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.018

Where:

CO2 emission rate = An affected EGU's calculated
CO2 emission rate that will be used to determine
compliance with the applicable CO2 emission standard.
MCO2 = Measured CO2 mass in units of pounds
(lbs) summed over the compliance period for an affected EGU.
MWhop = Total net energy output over the compliance
period for an affected EGU in units of MWh.
MWhERC = ERC replacement generation for an affected EGU
in units of MWh (ERCs are denominated in whole integers as specified
in paragraph (c)(2) of this section).

    (2) An ERC qualifies for the compliance demonstration specified in
paragraph (c)(1) of this section if it:
    (i) Has a unique serial number;
    (ii) Represents one whole MWh of actual energy generated or saved
with zero associated carbon dioxide emissions;
    (iii) Was issued to an eligible resource that meets the
requirements of Sec.  62.16435 or to an affected EGU that meets the
requirements of Sec.  62.16434, by the Administrator through an ERC
tracking system or the ATCS; and
    (iv) Was surrendered and retired only once for purposes of
compliance with this regulation by the Administrator through an ERC
tracking system or the ATCS.
    (3) An ERC does not qualify for the compliance demonstration
specified in paragraph (c)(1) of this section if it does not meet the
requirements of paragraph (c)(2) of this section or if any State has
used that same ERC for purposes of demonstrating achievement of its
state measures.
    (4) As of the ERC transfer deadline for a compliance period, the
owners and operators of each affected EGU must hold, in the affected
EGU's compliance account, sufficient ERCs to demonstrate compliance
with its applicable emission standard listed in Table 1 of this subpart
pursuant to the requirement of paragraph (c)(1) of this section.
    (5) If an affected EGU exceeds its emission standard during a
compliance period, then:
    (i) The owners and operators of the affected EGU must hold ERCs
required for deduction under Sec.  62.16535(e);
    (ii) The owners and operators of the affected EGU are subject to
federal enforcement pursuant to sections 113(a)-(h), and section 304,
of the Clean Air Act, and the United States, States, and other persons
have the ability to enforce against violations (including if an
affected EGU does not meet its emission standard based on its
emissions, or use of ERCs that meet the compliance demonstration in
Sec.  62.16420 (c)(2)) and secure appropriate corrective actions, and
the owners and operators must pay any fine, penalty, or assessment or
comply with any other remedy imposed, for the same violations, under
the Clean Air Act, and each day of such compliance period will
constitute a separate violation of this subpart and the Clean Air Act;
    (iii) If an affected EGU does not meet its emission standard
because it did not meet the emissions standard based on its stack
emissions and generation alone and it did not obtain sufficient
qualifying ERCs to meet its emission standard by July 1 of the year
following the relevant compliance period, then it may be subject to
federal enforcement pursuant to Sections 113(a)-(h), 42 U.S.C. 7413(a)-
(h), and Section 304 of the Clean Air Act, 42 U.S.C. 7604, and the
United States, states, and other persons have the ability to enforce
violations and secure corrective actions; and
    (iv) If an affected EGU obtained sufficient facially valid ERCs to
meet its emission standard, but those ERCs were found to be invalid,
then it may be subject to federal enforcement as specified in paragraph
(c)(5)(iii) of this section.
    (d) Compliance periods. An affected EGU will be subject to the
requirements under paragraph (c)(1) of this section for the compliance
period starting on January 1, 2022, and for each compliance period
thereafter.
    (1) Vintage of ERCs held for compliance. An ERC held for compliance
with the requirements under paragraph (c)(1) of this section for a
compliance period must be an ERC that was issued for a year in such
compliance period or for a year in a prior compliance period.
    (2) ATCS. Each ERC must be held in, deducted from, transferred
into, out of, or between ATCS accounts in accordance with this subpart.
    (3) Limited authorization. (i) An ERC shall only be used in
accordance with the CO2 Rate-based Trading Program; and
    (ii) Notwithstanding any other provision of this subpart, the
Administrator has the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act.
    (4) Property right. An ERC does not constitute a property right.
    (e) Title V permit requirements. (1) Unless otherwise specified in
this paragraph, all requirements of this subpart shall be applicable
requirements that must be included in an affected EGU's title V permit.
    (2) The applicable requirements of this subpart, as well as other
terms or conditions necessary to ensure compliance with the applicable
requirements, may be added to, or changed in, a title V permit using
minor permit modification procedures in accordance with Sec. Sec.
70.7(e)(2) and 71.7(e)(1) of this chapter, provided that such changes
do not conflict with any existing terms of the permit. This paragraph
explicitly provides that the addition of, or change to, an affected
EGU's description as described in the prior sentence is eligible for
minor permit modification procedures in accordance with Sec. Sec.
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of this chapter.
    (3) No title V permit revision will be required for any crediting,
holding, deduction, or transfer of ERCs in accordance with this
subpart, provided that the requirements applicable to such creditings,
holdings, deductions, or transfers of ERCs are already incorporated in
such permit.
    (f) Liability. Any provision of the CO2 Rate-based
Trading Program that applies to an affected EGU or the designated
representative of an affected EGU shall also apply to the owners and
operators of such affected EGU.
    (g) Effect on other authorities. No provision of the CO2
Rate-based Trading Program or exemption under Sec.  62.16415 shall be
construed as exempting or excluding the owners and operators, and the
designated representative, of an affected EGU from compliance with any
other provision of the applicable, approved state implementation plan,
a federally enforceable permit, or any other requirement of the Clean
Air Act.

Sec.  62.16425  How should I compute time under the CO2
Rate-based Trading Program?

    (a) Unless otherwise stated, any time period scheduled, under the
CO2 Rate-Based Trading Program, to begin on the occurrence
of an act or event shall begin on the day the act or event occurs.
    (b) Unless otherwise stated, any time period scheduled, under the
CO2 Rate-Based Trading Program, to begin before the
occurrence of an act or event will be computed so that the period ends
the day before the act or event occurs.
    (c) Unless otherwise stated, if the final day of any time period,
under the CO2 Rate-Based Trading Program, is not a business
day, then the time period will be extended to the next business day.

Sec.  62.16430  What are the administrative appeal procedures?

    The administrative appeal procedures for decisions of the
Administrator under the CO2 Rate-based Trading Program are
set forth in part 78 of this chapter.

Sec.  62.16431  How will the Clean Energy Incentive Program be
administered under the federal plan?

    (a)(1) The Administrator will participate in the Clean Energy
Incentive Program, established under subpart UUUU of part 60 of this
chapter, on behalf of any state for whom this subpart is promulgated as
a federal plan under section 111(d) of the Act. The Administrator will
award, on behalf of each such state, early action ERCs for generation
and savings achieved in 2020 and/or 2021 that result from the

following types of eligible renewable energy (RE) and demand-side
energy efficiency (EE) projects:
    (i) Metered wind power;
    (ii) Metered solar power; and
    (iii) Demand-side EE implemented in a low-income community.
    (2) Eligible RE projects must commence construction, and eligible
demand-side EE projects must commence implementation, after September
6, 2018 for those states on whose behalf the EPA is implementing the
federal plan. Eligible projects must be located in or benefit the state
on whose behalf the EPA is implementing the federal plan.
    (b) Early action ERCs will be distributed pursuant to a process to
be prescribed by the Administrator, and in a manner to be demonstrated
by the Administrator to have no impact on the aggregate emission
performance of affected EGUs required to meet rate-based emission
standards during the compliance periods.
    (c) The Administrator will match these early action ERCs with
additional matching ERCs pursuant to a process to be prescribed by the
Administrator. Matching awards will be made up to a limit equivalent to
the state's pro rata share of 300 million short tons of CO2
emissions.
    (d) The awards, including the matching award, will be executed as
follows:
    (1) For RE projects that generate metered MWh from wind or solar
resources: For every two MWh generated, the project will receive one
early action ERC under paragraph (b) of this section and one matching
ERC from the match under paragraph (c) of this section; and
    (2) For EE projects that benefit low-income communities as
determined by the Administrator solely for purposes of this subpart:
For every two MWh in end-use demand savings achieved, the project will
receive two early action ERCs under paragraph (b) of this section and
two matching ERCs from the match under paragraph (c) of this section.

Emission Rate Credit Issuance, Adjustment, and Revocation

Sec.  62.16434  What affected EGUs qualify for generation of ERCs?

    (a) ERCs may only be issued to affected EGUs under the conditions
listed in paragraphs (b) and (c) of this section.
    (b) For affected EGUs that emit below their applicable emission
standard, the amount of ERCs generated must be calculated using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.019

Where:

ERCs = Number of emission rate credits generated by an affected EGU
during an applicable compliance period (MWh).
EGU emission standard = The emission standard the affected EGU must
comply with during the applicable compliance period according to
Sec.  62.16420 (lb/MWh).
EGU emission rate = The affected EGU's measured CO2
emission rate measured in accordance with Sec.  62.16540 (lb/MWh).
EGU generation = Total net energy output generation of the affected
EGU during the applicable compliance period measured in accordance
with Sec.  62.16540 (MWh).

    (c) Stationary combustion turbines that meet the definition of an
affected EGU may generate net energy output MWh gas shift ERCs (GS-
ERCs) for all hours of operation during a given compliance period
according to paragraphs (c)(1) through (3) of this section.
    (1) To calculate the number of GS-ERCs:

    GS-ERCs = EGU Generation * Incremental Generation Factor * GS-ERC
Emission Factor

Where:

GS-ERC = Net energy output MWh gas shift ERCs.
EGU generation = Total net energy output generation of the affected
EGU during the applicable compliance period measured in accordance
with Sec.  62.16540 (MWh).
Incremental Generation Factor = See Table 2 of this subpart for the
applicable factor for each compliance period.
GS-ERC Emission Factor = Value calculated using equation (c)(2) of
this section.

    (2) To calculate the GS-ERC Emission factor for your specific
affected EGU you must use the following equation:
[GRAPHIC] [TIFF OMITTED] TP23OC15.020

Where:

GS-ERC Emission Factor = Factor to be used in the equation in
paragraph (c)(1) of this section for GS-ERC calculation.
EGU emission rate = Affected EGU's measured CO2 emission
rate measured in accordance with Sec.  62.16540 (lb/MWh).
Steam turbine emission standard = Steam turbine emission standard
for the corresponding compliance period as found in Table 1 of this
subpart (lb/MWh).

    (3) Notwithstanding any other provision of this subpart, GS-ERCs
must not be used for compliance by an affected EGU that is a stationary
combustion turbine. Stationary combustion turbines may use other ERCs
in their compliance demonstration.

Sec.  62.16435  What eligible resources qualify for generation of ERCs
in addition to affected EGUs?

    (a) ERCs may only be issued to an eligible resource that meet each
of the requirements in paragraphs (a)(1) through (4) of this section.
All categories of resources other than on-shore utility scale wind,
utility scale solar photovoltaics, concentrated solar power, geothermal
power, nuclear energy, or utility scale hydropower, and all provisions
of this subpart relating to such resources, are not available or
applicable in States where this subpart has been promulgated as a
federal plan pursuant to section 111(d)(2) of the Act.
    (1) Resources qualifying for eligibility only include resources
which increased new installed electrical generation nameplate capacity,
or new electrical savings measures installed or implemented after
January 1, 2013. If a resource had a nameplate capacity uprate, then
ERCs may be issued only for the difference in generation between the
uprated nameplate capacity and its nameplate capacity prior to the
uprate. ERCs must not be issued for generation for an uprate that
followed a derate that occurred on or after January 1, 2013. A resource
that is relicensed or receives a license extension is considered
existing

capacity and is not an eligible resource, unless it receives a capacity
uprate as a result of the relicensing process that is reflected in its
relicensed permit. In such a case, only the difference in nameplate
capacity between its relicensed permit and its prior permit is eligible
to be issued ERCs.
    (2) The resource must be connected to, and delivers energy to or
saves electricity, on the electric grid in the contiguous United
States.
    (3) The resource is located in a State whose affected EGUs are
subject to rate-based emission standards pursuant to this regulation,
unless the resource is located in a State with mass-based emission
standards and the resource can demonstrate (e.g., through a power
purchase agreement or contract for delivery) transmission of its
generation into a State whose affected EGUs are subject to rate-based
emission standards pursuant to this regulation.
    (4) The resource falls into one of the following categories of
resources:
    (i) Renewable electric generating technologies using one of the
following renewable energy resources: wind, solar, geothermal, hydro,
wave, tidal;
    (ii) Qualified biomass;
    (iii) Waste-to-energy (biogenic portion);
    (iv) Nuclear energy;
    (v) A non-affected combined heat and power unit, including waste
heat power; or
    (vi) A demand-side EE or demand-side management measure that saves
electricity and is calculated on the basis of quantified ex poste
savings, not ``projected'' or ``claimed'' savings.
    (b) Any resource that does not meet the requirements of this
subpart cannot generate ERCs for use in the compliance demonstration
required under Sec.  62.16420.
    (c) ERCs may not be issued to any of the following:
    (1) New, modified, or reconstructed EGUs that are subject to
subpart TTTT of part 60 of this chapter, except CHP units that meet the
requirements of a CHP unit under paragraph (a) of this section;
    (2) EGUs that do not meet the applicability requirements of Sec.
62.16410, except CHP units that meet the requirements of a CHP unit
under paragraph (a) of this section;
    (3) Measures that reduce CO2 emissions outside the
electric power sector, including GHG offset projects representing
emission reductions that occur in the forestry and agriculture sectors,
direct air capture, and crediting of CO2 emission reductions
that occur in the transportation sector as a result of vehicle
electrification; and
    (4) Any measure not approved by the EPA to generate ERCs in
connection with a specific State plan.

Sec.  62.16440  What is the process for revocation of qualification
status of an eligible resource?

    (a) If an eligible resource is found to not meet the requirements
of Sec.  62.16435 in the Rate-based Trading Program, then the
Administrator will revoke the eligibility of the eligible resource to
be issued ERCs. In addition, the provisions of Sec.  62.16450(d) may
apply.
    (b) Any instance of intentional misrepresentation in an eligibility
application or monitoring and verification (M&V) report may be cause
for revocation of the qualification status of an eligible resource.
    (c) Repeated instances of error or misstatement of MWh of
electricity generation or savings in submitted M&V reports, or in any
other submissions may be cause for the Administrator to revoke the
eligibility of an eligible resource to be issued ERCs.
    (d) In the event of an intentional misrepresentation, or repeated
instances of error or misstatement, in program submissions, by the
authorized account representative of the eligible resource, the
Administrator may prohibit the eligible resource from any further
eligibility to be issued ERCs. In addition, the provisions of Sec.
62.16450 (a) through (d) may apply.

Sec.  62.16445  What is the process for the issuance of ERCs?

    The process and requirements for issuance of ERCs for affected EGUs
and eligible resources are set forth in paragraphs (a) through (f) of
this section.
    (a) Eligibility application. To receive ERCs, an authorized account
representative of an eligible resource must submit an eligibility
application to the Administrator that demonstrates that the
requirements of Sec.  62.16434 (for an affected EGU) or Sec.  62.16435
(for an eligible resource) are met, and, in the case of an eligible
resource only, demonstrates that the requirements in paragraphs (a)(1)
through (9) of this section are met.
    (1) Identification of the authorized account representative of the
eligible resource, including the authorized account representative's
name, address, email address, telephone number, and ERC tracking system
account number.
    (2) Identification of the eligible resource(s), including the
information in paragraphs (a)(2)(i) through (v) of this section.
    (i) For an eligible resource, the physical location of the eligible
resource; contact information for the owner or operator of the eligible
resource, if different from the designated representative or authorized
account representative; eligible resource generator prime mover and/or
technology type; eligible resource nameplate capacity; eligible
resource category (e.g., wholesale generator, wholesale generator also
serving onsite customer load, customer-sited distributed generator) (if
applicable); facility and generating unit IDs (EIA ORIS Code, Facility
Registration System (FRS) Code, if applicable); for the eligible
resource, the control area, balancing authority, ISO conditions as
defined in Sec.  62.16570, or the regional transmission organization in
which the generator is located (if applicable).
    (A) For an eligible resource with a nameplate capacity of1 MW or
more, a copy of the most recent filing of a copy of the generating
facility's U.S. Energy Information Agency's Annual Electric Generator
Report Form EIA-860.
    (B) For an electric generating resource with a nameplate capacity
of less than 1 MW, the information that would be contained in U.S.
Energy Information Agency's Annual Electric Generator Report Form EIA-
860, if that electric generating facility had nameplate capacity of 1
MW or more.
    (ii) For an energy-saving resource that is project-based, a
detailed description of the demand-side EE or electricity savings
project, including: Location and specifications of the building(s),
facility(ies), or installations where energy-saving measures were
implemented or will be implemented; owner and operator of the
building(s), facility(ies), or installations where the energy-saving
measures are implemented or will be implemented; the parties
implementing the energy-saving project, including lead contractor(s),
subcontractors, and consulting firms (if different from the authorized
account representative); energy-saving measures installed and/or
energy-savings practices implemented (or to be installed/implemented);
specifications of equipment and materials installed, or to be
installed, as part of the energy-saving project; project plans and
technical schematics, as applicable.
    (iii) For an energy-savings resource that involves an EE
requirement or program, a description of the electricity savings
program, including: Overall approach or ``logic'' to the requirement or
program, including applicable strategies and activities, along with key
assumptions regarding how such strategies and activities will achieve
quantifiable reductions in electricity consumption; location and
geographic

distribution of the targeted building(s), facility(ies), or
installations where energy-saving requirements or programs were
implemented or will be implemented; electricity consuming system(s),
end-use(s), building or facility type(s), or installations where the
energy-saving requirements or programs are implemented or will be
implemented; the parties implementing the energy-saving requirement or
program, including lead contractor(s), subcontractor(s), and consulting
firms (if different from the authorized account representative);
specifications of energy-saving equipment and/or energy-savings
practices implemented (or to be installed/implemented) under the
requirement or program; the delivery mechanisms of the requirement or
program, which may include financial incentives or equipment rebates,
dissemination of actionable information to electricity customers, on-
site audits paired with technical recommendations.
    (iv) For other electricity-saving resources (e.g., transmission and
distribution (T&D) measures such as conservation voltage reduction
(CVR)), a description of the resource, including: Overall approach or
``logic'' to the electricity-saving resource, including applicable
strategies and activities, along with key assumptions regarding how
such strategies and activities will achieve quantifiable reductions in
electricity consumption; location and geographic distribution of the
targeted building(s), facility(ies), or electricity transmitting and
distributing systems, as applicable, where electricity-saving resources
were implemented or will be implemented; electricity consuming,
transmitting, or distributing system(s), building or facility type(s),
or end-use(s) where the electricity-saving resource are implemented or
will be implemented; the parties implementing the electricity-saving
resource, including lead contractor(s), subcontractor(s), and
consulting firms (if different from the authorized account
representative); specifications of installed equipment and/or
implemented practices (or to be installed/implemented); the delivery
mechanisms used to implement and propagate the electricity-saving
resource, as applicable.
    (v) For eligible resources with distributed locations, such as
measures at multiple residential, commercial, or industrial buildings,
at a minimum, aggregated information about the location of measures
that constitute an eligible resource, provided that the accredited
independent verifier and the Administrator have the ability to access
information specifying the location of each discrete measure that
constitutes an eligible resource.
    (3) Demonstration that the eligible resource meets all applicable
eligibility requirements in Sec.  62.1435.
    (4) A certification that the eligibility application has only been
submitted to the Administrator or pursuant to an EPA-approved multi-
state approach where States are providing for joint issuance of ERCs
pursuant to the authority in their individual State plans.
    (5) An evaluation measurement and verification (EM&V) plan.
    (6) A verification report from an accredited independent verifier
who meets the requirements of Sec. Sec.  62.16470 and 62.16475.
    (7) An authorization that provides for the following: The
Administrator may inspect (including a physical inspection of the
eligible resource and its meter) and/or audit the eligible resource at
any time and verify that the eligible resource and the EM&V plan have
been implemented as described in the eligibility application.
    (8) The following statement, signed by the designated
representative of the eligible resource:
    (i) ``I certify under penalty of law that I have personally
examined, and am familiar with, the statements and information
submitted in this document and all its attachments. Based on my
personal knowledge and/or inquiry of those individuals with primary
responsibility for obtaining the information, I certify that the
statements and information are to the best of my knowledge and belief
true, accurate, and complete. I am aware that there are significant
penalties for submitting false statements and information or omitting
required statements and information, including the possibility of fine
or imprisonment.''
    (ii) [Reserved]
    (9) Any other information required by the Administrator.
    (b) Registration of eligible resources. The Administrator must
review the eligibility application to determine whether the affected
EGU or eligible resource meets the requirements of Sec.  paragraph (a)
of this section, and if it determines that the requirements are met,
approve the eligibility application and register the affected EGU or
eligible resource in an ERC tracking system that meets the requirements
of Sec.  62.16515. Once so registered, the affected EGU or eligible
resource is eligible to be issued ERCs, provided all other applicable
requirements continue to be met.
    (c) M&V reports. For an eligible resource, the designated
representative must submit to the Administrator an M&V report prior to
issuance of ERCs by the Administrator.
    (d) Verification reports. For an eligible resource, the authorized
account representative must submit a verification report from an
accredited independent verifier that meets the requirements of
Sec. Sec.  62.16470 and 62.16475 as part of each eligibility
application and M&V report. While considered a part of the eligibility
application and M&V report, the verification report must be submitted
separately by the accredited independent verifier to the Administrator.
    (e) Issuance of ERCs. ERCs may only be issued by the Administrator
based on actual electricity generation or savings documented in an M&V
report that meets the requirements of Sec.  62.16460 and a verification
report that meets the requirements of Sec.  62.16465. Only one ERC will
be issued for each verified MWh.
    (f) Tracking system. ERCs may only be issued through an ERC
tracking system that meets the requirements of Sec.  62.16515.

Sec.  62.16450  What is the process for error adjustments or
misstatement, and suspension of ERC issuance?

    (a) In the event of error or misstatement of quantified MWh of
electricity generation or savings in a previous M&V report for which
ERCs have been issued, the Administrator may adjust the number of ERCs
issued in a subsequent reporting period to address the error or
misstatement, by subtracting a number of MWh from the quantified and
verified MWh in the M&V report for the subsequent reporting period. In
the event that an error or inadvertent misstatement occurs in a final
M&V report for an eligible resource, for which ERCs have been issued,
the provisions of paragraph (b) of this section will apply.
    (b) In the event of error or misstatement of quantified MWh of
electricity generation or savings in the final M&V report for an
eligible resource, for which ERCs have been issued, the Administrator
will revoke ERCs from the general account held by the authorized
account representative of the eligible resource, in an amount necessary
to correct the error or misstatement. In the event that the general
account of the eligible resource holds an insufficient number of ERCs
to correct the error or misstatement, the authorized account
representative must submit to the Administrator within 30 days a number
of ERCs necessary to correct the error or misstatement. Failure to meet
this requirement will

result in prohibition of the authorized account representative for the
eligible resource from further participation in the program, unless
reauthorized at the discretion of the Administrator.
    (c) The Administrator may freeze the general account held by an
authorized account representative of an eligible resource at any time,
for cause, if the Administrator determines ERCs have been improperly
issued, based on a misrepresentation or misstatement in an eligibility
application or M&V report. The Administrator may also freeze the
general account of an authorized account representative of an eligible
resource pending investigation of potential misrepresentation, error,
or misstatement in an eligibility application of an eligible resource,
or in an M&V report for which ERCs have been issued. Freezing a general
account will prevent transfer of ERCs out of the account.
    (d) If ERCs are issued for an eligible resource that is found to be
ineligible, then the Administrator may take the actions in paragraphs
(d)(1) through (3) of this section.
    (1) Freeze the general account for the eligible resource,
preventing any transfers of ERCs out of the account.
    (2) Revoke and deduct ERCs held in the general account of the
authorized account representative for an eligible resource, in a number
equal to the number of ERCs issued for the ineligible eligible
resource.
    (3) In the event that the general account of the eligible resource
holds a number of ERCs less than the number of ERCs issued for the
ineligible eligible resource, the delegated representative of an
eligible resource must submit to the Administrator within 30 days a
number of ERCs necessary to fully account for all ERCs issued for the
ineligible eligible resource. Failure to meet this requirement will
result in prohibition of the eligible resource from further
participation in the program, unless reauthorized at the discretion of
the Administrator.
    (e) The Administrator may temporarily or permanently suspend
issuance of ERCs for an eligible resource, for the following reasons in
paragraphs (e)(1) through (3) of this section.
    (1) Pending investigation of potential misrepresentation, error, or
misstatement in an M&V report, for which ERCs have been issued, or the
eligibility status of an eligible resource.
    (2) In the case of repeated error or misstatements in submitted M&V
reports.
    (3) In the case of an intentional misrepresentation in a submitted
M&V report.

Evaluation Measurement and Verification Plans, Monitoring and
Verification Reports, and Verification

Sec.  62.16455  What are the requirements for evaluation measurement
and verification plans for eligible resources?

    (a) EM&V plan requirements. Any EM&V plan submitted in support of
the issuance of an ERC pursuant to this rule must meet the requirements
of this section.
    (b) General EM&V plan criteria. Each EM&V plan must identify the
eligible resource and its approved eligibility application.
    (c) Specific EM&V plan criteria. Each EM&V plan must provide the
manner in which the electricity generated or saved by the eligible
resource will be quantified, monitored and verified, and the manner of
quantification, monitoring and verification must meet the criteria
listed in paragraphs (c)(1) through (7) of this section, as applicable
to the specific eligible resource.
    (1) For a nuclear energy resource or a renewable energy resource
with a nameplate capacity of 10 kW or more and for a renewable energy
resource with a nameplate capacity of less than 10 kW for which metered
data are available, each EM&V plan must specify that the requirements
in paragraphs (c)(1)(i) through (vi) of this section are met.
    (i) The generation data are physically measured on a continuous
basis using a revenue-quality meter, which means a meter used by a
control area operator for financial settlements, or a meter that meets
the American National Standards Institute No. C12.20., Code for
Electricity Metering, metering accuracy standards, or a meter that
meets an alternative equivalent standard that has been approved in
advance of its use to measure generation pursuant to this regulation by
the EPA.
    (ii) The generating data are measured at the generator's bus bar,
or, for a renewable energy resource with a nameplate capacity of less
than 10 kW that is interconnected behind an individual business or
household meter, the generating data were measured at the AC output of
the inverter and adjusted to reflect the only energy delivered into
either the transmission or distribution grid at the generator bus bar
and not any energy used on-site at the generator.
    (iii) The generation data from only one eligible resource
generating unit may be associated with each meter, and generation data
may not be aggregated, unless all the following provisions are met:
    (A) All of the generating units have the same essential generation
characteristics;
    (B) All of the generating units are located in the same State;
    (C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
    (D) The generation data are measured by the same type of meter that
is subject to the same maintenance and quality assurance procedures.
    (iv) The generation data are collected electronically and
telemetered from the generator to its control area operator and
verified through a control area energy accounting or settlement process
which occurs at least monthly, unless the generation unit does not go
through a control area operator, in which case the generation data must
be collected by manual meter readings conducted by an independent
verifier that is either not affiliated with the owner or operator of
the qualifying renewable energy generating resource or is precluded
pursuant to the relevant State plan from the ability to transfer or
retire ERCs issued to that qualifying renewable energy generating
resource or, if the generating unit is less than 10 kw and does not
generate enough electricity to enable monthly reporting, then the data
may be self-reported and reported no less than annually.
    (v) The generation data serve a load that otherwise would have been
served by the grid if not for the generator. Specifically:
    (A) ERCs shall not be issued for energy generation used to supply
the ancillary equipment used to operate a generating station or
substation (``station service'') or parasitic load on the generator's
side of the point of interconnection; and
    (B) For generators interconnected to transmission systems and with
on-site loads other than station service drawing generation before the
metering point, ERCs may be issued for on-site load, if the owner or
operator of the eligible resource can demonstrate that the metering
used is capable of distinguishing between on-site load and station
service.
    (vi) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.

    (2) For a renewable energy resource with a nameplate capacity of
less than 10 kW and that does not have a meter, each EM&V plan must
require that the following requirements in paragraphs (c)(2)(i) though
(vii) of this section are met.
    (i) Metered data are unavailable.
    (ii) At least 1 MW of net energy output is generated to the
distribution or transmission system over a continuous 365-day period.
    (iii) The generation data may not be aggregated, unless the
following provisions are met:
    (A) All of the generating units have the same essential generation
characteristics;
    (B) All of the generating units are located in the same State;
    (C) The nameplate capacity of the individual units being aggregated
is each less than 150 kW, and units collectively do not exceed a total
nameplate capacity of 1 MW when aggregated, or alternative requirements
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan or M&V report is submitted; and
    (D) The generation data are measured by the same generation
estimating software or algorithms.
    (iv) The generation data are measured on at least a monthly basis
using generation estimating software or algorithms that are based on an
on-site inspection prior to interconnection and a resource study (wind,
shading, solar irradiance, depending on the resource), or engineering
information that takes into account the capacity, age, and type of
qualifying energy generating resource, and all input parameters and
assumptions must be clearly delineated, or if the generating unit does
not generate enough electricity to enable monthly reporting, then the
data may be reported no less than annually.
    (v) The generation data are self-reported to the distribution
utility through an electronic internet-based portal with software that
reports total and hourly generation.
    (vi) The generation data serve a load that otherwise would have
been served by the grid if not for the generator. The ERC is only based
on generation transferred from the eligible resource to the
transmission or distribution grid, and is not based on the generation
used on-site by the customer.
    (vii) Any other requirements approved by the EPA in connection with
the specific State plan pursuant to which that EM&V plan is submitted.
    (3) For qualified biomass feedstocks used, in addition to the
requirements of paragraphs (c)(1) or (2) of this section, whichever
section is applicable, each EM&V plan must demonstrate that the
requirements approved by the EPA for that biomass feedstock, and its
associated biogenic CO2, have been met.
    (4) For a waste-to-energy resource, in addition to the requirements
of paragraphs (c)(1) or (2) of this section, as applicable, and
paragraph (c)(3) of this section, each EM&V plan must specify:
    (i) The total net energy generation from the resource in MWh;
    (ii) The method for determining the specific portion of the total
net energy output from the resource that is related to the biogenic
portion of the waste materials; and
    (iii) The net energy output measured with the relevant method
approved by the EPA in connection with the specific State plan pursuant
to which that EM&V plan is submitted demonstrates that the requirements
approved by the EPA in connection with that State plan have been met.
    (5) For a combined heat and power unit, in addition to the
requirements of paragraphs (c)(1) or (2) of this section, as
applicable, and paragraph (c)(3) of this section, each EM&V plan must
meet one of the requirements in paragraphs (c)(5)(i) through (iv) of
this section, as applicable, and any other requirements approved by the
EPA.
    (i) If the combined heat and power unit has an electric generating
capacity greater than 25 MW, then the EM&V plan must meet the
requirements that apply to an affected EGU under Sec.  62.16540.
    (ii) If the combined heat and power unit has an electric generating
capacity less than or equal to 25 MW and greater than 1 MW, and it uses
only natural gas and/or distillate fuel oil, then the EM&V plan must
meet the low mass emission unit CO2 emission monitoring and
reporting methodology in part 75 of this chapter.
    (iii) If the combined heat and power unit has an electric
generating capacity less than or equal to 25 MW and greater than 1 MW,
and it uses anything other than only natural gas and/or distillate fuel
oil, then the EM&V plan must meet the low mass emission unit
CO2 emission monitoring and reporting methodology in part 75
of this chapter.
    (iv) If the combined heat and power unit has an electric generating
capacity less than or equal to 1 MW the unit must keep monthly
cumulative recordings of useful thermal output and fossil fuel input
along with the determination of baseline thermal source efficiencies
based on manufacturer data. For CHP units that directly serve on-site
end-use electricity loads, avoided T&D system losses can be assessed as
is commonly practiced with demand-side EE.
    (6) For demand-side electricity savings that avoid a transmission
and distribution loss, each EM&V plan must measure the transmission and
distribution loss based on the lesser of 6 percent of the facility- or
premises-level electricity savings measured at the electricity
customer's meter, or the statewide annual average transmission and
distribution loss rate (expressed as a percentage) from the most recent
year that is published in the US EIA State Electricity Profile. No
other transmission and distribution loss factors may be used in
calculating the electricity savings.
    (7) Each EM&V plan for an EE program, EE project, or EE measure
must specify how each of the requirements in paragraphs (c)(7)(i)
through (x) of this section will be met in quantifying the electricity
savings from that EE program, EE project, or EE measure.
    (i) All electricity savings must be quantified on an ex-post basis,
which means after the electricity savings have occurred, or on a real-
time basis, which means at the time the electricity savings are
occurring. Electricity savings must not be quantified on an ex-ante
basis, which means estimates of MWh savings that are generated prior to
implementing the subject EE program, EE project, or EE measure, and
that are not quantified using EM&V methods and procedures.
    (ii) All electricity savings must be quantified and verified based
on methods and procedures detailed in an industry best-practice EM&V
protocol or guideline. Each EM&V plan must include a demonstration of
how the best-practice protocol or guideline was selected and will be
applied to the specific EE program, EE project, or EE measure covered
in the EM&V plan, and an explanation of why that particular protocol or
guideline was selected. Protocols and guidelines are considered to be
best practice if they:
    (A) Have gone through a rigorous and credible peer review process
that shows the applicable methods to be valid through empirical
testing; and
    (B) Have been accepted and approved for use by identifiable state
regulatory commissions. Examples of such protocols and guidelines that
may be provided in EM&V guidance issued by the Administrator will be
acceptable.
    (iii) All electricity savings must be quantified as the difference
between the observed electricity use and a common practice baseline
(CPB), which is the equipment that would typically have been
installed--or that a typical

consumer or building owner would have continued using--in a given
circumstance (i.e., a given building type, EE program type or delivery
mechanism, and geographic region) at the time of EE implementation.
Examples of CPBs for specific EE programs, EE projects, EE measures,
and for certain EM&V methods that may be provided in EM&V guidance
issued by the Administrator will be acceptable. The EM&V plan must
specify the reason the specific CPB was selected, which must include an
analysis of the appropriateness of that CPB for the EE program, EE
project, or EE measure covered in the EM&V plan, based on:
    (A) Characteristics of the EE program, EE project, or EE measure;
    (B) The delivery mechanism used to implement the EE program, EE
project, or EE measure (e.g., installed as part of a utility EE program
versus a point-of-sale rebate);
    (C) Local consumer and market characteristics;
    (D) Applicable building energy codes and standards and average
compliance rates; and
    (E) The method applied: Project-based measurement and verification
(PB-MV), comparison group approaches, or deemed savings.
    (iv) All electricity savings must be quantified by applying one or
more of the following methods: Project-based measurement and
verification (PB-MV), comparison group approaches, or deemed savings.
    (A) If a comparison group approach is used, then the EM&V plan must
quantify electricity savings by taking the difference between a
comparison group's electricity use and the electricity use of EE
program participants. Comparison group approaches may include
randomized control trials and quasi-experimental methods, as described
in industry best-practice protocols and guidelines. Examples of such
protocols and guidelines provided in EM&V guidance that may be issued
by the Administrator will be acceptable.
    (B) If deemed savings are used, then the EM&V plan must specify
that the deemed savings values will only be used for the specific EE
measure for which they were derived. The EM&V plan must also specify
the name and Web address of the technical reference manual (TRM) in
which all deemed electricity savings values will be documented. Prior
to use in an EM&V plan, all TRMs must undergo a review process in which
the public, stakeholders, and experts are invited--with adequate
advance notification (via the internet and other social media)--to
provide comment, have at least 2 months to provide comment, and in
which all such comments and associated responses are made publicly
available. All TRMs must also be publicly accessible over the full
period of time in which they are being used in conjunction with an EM&V
plan for the purpose of quantifying savings, and must be subsequently
updated in the same manner at least every 3 years. The TRM must
indicate, for each subject EE measure, the associated electricity
savings value, the conditions under which the value can be applied
(including the climate zone, building type, manner of implementation,
applicable end uses, operating conditions, and effective useful life),
and the manner in which the electricity savings value was quantified,
which must include applicable engineering algorithms, source
documentation, specific assumptions, and other relevant data to support
the quantification of savings from the subject EE measure.
    (v) All EE programs, EE projects, or EE measures must be quantified
at time intervals (in years) sufficient to ensure that MWh savings are
accurately and reliably quantified. Such time intervals must be
specified and explained in the EM&V plan. Factors that must be taken
into consideration when determining the appropriate time interval
include the characteristics of the specific EE program, EE project, or
EE measure, expected variability in electricity savings (where greater
variability necessitates more frequent quantification), the expected
scale and magnitude of the electricity savings (where greater
quantities of savings necessitate more frequent quantification), and
the experience implementing and quantifying savings from the resource
(where less experience--for example, with new and innovative EE program
types--necessitates more frequent quantification). The time intervals
must end no sooner than the last day of the effective useful life of
the EE program, EE project, or EE measure, and must last no longer
than:
    (A) Every 4-year intervals for building energy codes and product
standards;
    (B) Every 1, 2, or 3 years for public or consumer-funded EE
program, EE project, or EE measure, as relevant for the type of EE
program, EE project, or EE measure and factors listed in paragraph
(c)(7)(v) of this section; and