1

SUPPORTING STATEMENT

ENVIRONMENTAL PROTECTION AGENCY

Standards of Performance for Greenhouse Gas Emissions from Newly Constructed, 

Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units

(40 CFR part 60, subpart TTTT) 

July 2015

Part A of the Supporting Statement

1. Identification of the Information Collection

(a) Title and Number of the Information Collection

“Recordkeeping and Reporting Requirements for Standards of Performance for 

Greenhouse Gas Emissions from Newly Constructed, Modified, and Reconstructed Electric 

Utility Generating Units (40 CFR Part 60, Subpart TTTT).” The standards would establish 

standards of performance for carbon dioxide (CO2) emissions from electric utility generating 

units (EGUs). An EGU is any boiler, integrated gasification combined cycle (IGCC) unit, or 

combustion turbine (CT) (in either simple cycle or combined cycle configuration) that meets the 

rule’s applicability criteria. An information collection request (ICR) has been prepared in support 

of the standards being established under subpart TTTT. The Environmental Protection Agency

(EPA) ICR tracking number is 2465.03. Separate ICR documents were prepared and submitted 

to OMB for the proposed standards for newly constructed EGUs (EPA ICR number 2465.02) 

and the proposed standards for modified and reconstructed EGUs (EPA ICR number 2506.03). 

Because the CO2 standards for newly constructed, modified, and reconstructed EGUs will be 

included in the same new subpart (40 CFR part 60, subpart TTTT) and are being finalized in the 

same action, the ICR document for this action includes estimates of the information collection 

burden on owners and operators of newly constructed, modified, and reconstructed EGUs. This 

ICR was developed for the 3-year period following publication of the final rule.

(b) Short Characterization

On June 25, 2013, in conjunction with the announcement of his Climate Action Plan 

(CAP), President Obama issued a Presidential Memorandum directing the EPA to issue a new 

proposal to address carbon pollution from new power plants by September 30, 2013, and to issue 

“standards, regulations, or guidelines, as appropriate, which address carbon pollution from 

modified, reconstructed, and existing power plants.” Among stationary sources in the U.S., fossil 

fuel-fired EGUs are by far the largest emitters of greenhouse gas (GHG) pollution, primarily in 

the form of CO2. The EPA in 2009 found that by causing or contributing to climate change, 

GHGs endanger both the public health and the public welfare of current and future generations.

Pursuant to authority in section 111(b) of the Clean Air Act (CAA), on September 20, 

2013, EPA Administrator Gina McCarthy signed proposed carbon pollution standards for newly 

constructed fossil fuel-fired power plants. 79 FR 1430 (January 8, 2014) (“January 2014 

proposal”). Specifically, the EPA proposed new source performance standards (NSPS) to limit 
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emissions of CO2 from newly constructed fossil fuel-fired electric utility steam generating units

and newly constructed natural gas-fired stationary combustion turbines. The final standards for 

newly constructed fossil fuel-fired EGUs apply to those sources that commenced construction on 

or after January 8, 2014.

On June 2, 2014, Administrator McCarthy signed proposed standards of performance, 

also pursuant to CAA section 111(b), to limit emissions of CO2 from modified and reconstructed 

fossil fuel-fired electric utility steam generating units and natural gas-fired stationary combustion 

turbines. 79 FR 34959 (June 18, 2014) (“June 2014 proposal”). The final standards for modified 

and reconstructed fossil fuel-fired EGUs apply to those sources that that modify or reconstruct on 

or after June 18, 2014. The CAA and EPA’s regulations define an NSPS “modification” as a 

physical or operational change that increases the source’s maximum achievable hourly rate of 

emissions, with certain exceptions.

1 Under the EPA’s CAA section 111 standards of performance 

for new stationary sources, reconstructed sources are defined, in general, as existing sources (i) 

that replace components to such an extent that the capital costs of the new components exceed 50 

percent of the capital costs of an entirely new facility, and (ii) for which compliance with 

standards of performance for new sources is technologically and economically feasible.

2

To be considered an EGU the unit must be (1) capable of combusting more than 250 

MMBtu/h heat input of fossil fuel and (2) serve a generator capable of supplying more than 25 

MW net to a utility distribution system (i.e., for sale to the grid). However, GHG standards are 

not being finalized for certain EGUs: (1) non-fossil fuel units subject to a federally enforceable 

permit that limits the use of fossil fuels to 10 percent or less of the heat input capacity on an 

annual basis; (2) combined heat and power (CHP) units that are subject to a federally enforceable 

permit limiting annual net-electric sales to no more than the unit’s design efficiency multiplied 

by its potential electric output, or 219,000 MWh or less, whichever is greater; (3) stationary

combustion turbines that are not physically capable of combusting natural gas (e.g., not 

connected to a natural gas pipeline); (4) utility boilers and IGCC units that have always been 

subject to a federally enforceable permit limiting annual net-electric sales to one-third or less of 

their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) 

or limiting annual electric sales to 219,000 MWh or less; (5) municipal waste combustors that 

are subject to subpart Eb of part 60; and (6) commercial or industrial solid waste incineration 

units subject to subpart CCCC of part 60.

Consistent with the requirements of CAA section 111(b), the final standards reflect the 

degree of emission limitation achievable through the application of the best system of emission 

reduction (BSER) that the EPA has determined has been adequately demonstrated for each type 

of unit. The BSER determinations and final standards of performance for affected newly 

constructed, modified, and reconstructed EGUs are summarized below in Table 1.

Table 1. Summary of BSER and Final Standards for Affected Sources

Affected Sources BSER Final Standards of Performance

 

1 CAA §111(a)(4); 40 CFR 60.2, 60.14.

2

40 CFR 60.15.
3

Newly Constructed 

Fossil Fuel-Fired 

Steam Generating 

Units

Efficient new 

supercritical 

pulverized coal 

(SCPC) utility

boiler 

implementing 

partial carbon 

capture and 

storage (CCS)

1,400 lb CO2/MWh-gross.

Modified Fossil 

Fuel-Fired Steam 

Generating Units

Most efficient 

generation at the 

affected source 

achievable 

through a 

combination of 

best operating 

practices and 

equipment 

upgrades 

Sources making modifications

resulting in an increase in CO2 hourly emissions of 

more than 10 percent are required to meet a unitspecific emission limit determined by the unit’s best 

historical annual CO2 emission rate (from 2002 to 

the date of the modification); the emission limit will 

be no more stringent than:

1. 1,800 lb CO2/MWh-gross for sources with heat 

input > 2,000 MMBtu/h.

OR

2. 2,000 lb CO2/MWh-gross for sources with heat 

input ≤ 2,000 MMBtu/h.

Reconstructed 

Fossil Fuel-Fired 

Steam Generating 

Units

Most efficient 

generating 

technology

at the 

affected

source 

(supercritical 

steam conditions 

for the larger; and 

subcritical 

conditions for the 

smaller)

1. Sources with heat input > 2,000 MMBtu/h are

required to meet an emission limit of 1,800 lb 

CO2/MWh-gross.

2. Sources with heat input ≤ 2,000 MMBtu/h are

required to meet an emission limit of 2,000 lb 

CO2/MWh-gross.

Newly Constructed 

and Reconstructed 

Fossil Fuel-Fired 

Stationary

Combustion 

Turbines

Efficient natural 

gas combined 

cycled (NGCC)

technology for 

natural gas-fired 

base load units 

and clean fuels for 

non-base load and 

multi-fuel-fired 

units

1. 1,000 lb CO2/MWh-gross or

1,030 lb CO2/MWh-net for nominal base load 

natural gas-fired units.

2. 120 lb CO2/MMBtu for non-base load natural 

gas-fired units.

3. 120 to 160 lb CO2/MMBtu for multi-fuel-fired 

units.3

 

3

The emission standard for combustion turbines co-firing natural gas with other fuels is

determined at the end of each operating month based on the amount of co-fired natural gas.
4

Fossil fuel-fired electric utility steam generating units

The final rule establishes standards of performance for newly constructed fossil fuel-fired 

steam generating units (steam generating units; utility boilers and IGCC units) based on the 

performance of a new SCPC unit implementing partial implementation of CCS technology as the 

BSER. The EPA is finalizing an emission standard for newly constructed fossil fuel-fired steam 

generating units at 1,400 lb CO2/MWh-gross. The EPA finds that IGCC technology – either 

alone or implementing partial CCS – is not part of the BSER, but rather is an alternative 

compliance option. A newly constructed, highly efficient SCPC utility boiler burning bituminous 

coal will be able to meet this final standard of performance by capturing and storing 

approximately 16 percent of the CO2 produced from the facility. As an alternative compliance 

option, utilities and project developers will also be able to construct new steam generating units 

(both utility boilers and IGCC units) that meet the final standard of performance by co-firing 

with natural gas.

The EPA is also issuing final standards for steam generating units that implement “large 

modifications,” (i.e., modifications resulting in an increase in hourly CO2 emissions of more than 

10 percent when compared to the source’s highest hourly emissions in the previous 5 years). The 

EPA is not issuing final standards, at this time, for steam generating units that implement “small 

modifications” (i.e., modifications resulting in an increase in hourly CO2 emissions of less than 

or equal to 10 percent when compared to the source’s highest hourly emissions in the previous 5 

years). The standards of performance for modified steam generating units that make large 

modifications are based on each affected unit’s own best potential performance as the BSER. 

Specifically, such a modified steam generating unit will be required to meet a unit-specific CO2

emission limit determined by that unit's best demonstrated historical performance (in the years 

from 2002 to the time of the modification). The EPA has determined that this standard based on 

each unit’s own best potential performance can be met through a combination of best operating 

practices and equipment upgrades and that these steps can be implemented cost-effectively at the 

time when a source is undertaking a large modification. To account for facilities that have 

already implemented best practices and equipment upgrades, the final rule also specifies that 

modified facilities will not have to meet an emission standard more stringent than the 

corresponding standard for reconstructed steam generating units.

The EPA is not promulgating final standards of performance for, and is withdrawing the 

proposed standards for, modified steam generating sources that make modifications resulting in 

an increase of hourly CO2 emissions of less than or equal to 10 percent. As we indicated in the 

proposal, the EPA has been notified of very few modifications for criteria pollutant emissions 

from the power sector to which NSPS requirements have applied. As such, we expect that there 

will be few NSPS modifications for GHG emissions as well. We do not have sufficient 

information at this time, however, to anticipate the types of modifications, if any, that may result 

from these changes. In particular, we do not have sufficient information about the types of 

modifications, if any, that would result in increases in CO2 emissions of 10 percent or less, and 

what the appropriate standard for such sources would be. Therefore, we conclude that it is 

prudent to delay issuing standards for sources that undertake small modifications (i.e., those 

resulting in an increase in CO2 emissions of less than or equal to 10 percent).
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For reconstructed steam generating units, the EPA is finalizing standards based on the 

performance of the most efficient generating technology for these types of units as the BSER 

(i.e., reconstructing the boiler if necessary to use steam with higher temperature and pressure, 

even if the boiler was not originally designed to do so.) The emission standard for these sources 

is 1,800 lb CO2/MWh-gross for large sources, (i.e. those with a heat input rating of greater than 

2,000 MMBtu/h) or 2,000 lb CO2/MWh-gross for small sources (i.e., those with a heat input 

rating of 2,000 MMBtu/h or less). The difference in the standards for larger and smaller units is 

based on greater availability of higher pressure/temperature steam turbines (e.g., supercritical 

steam turbines) for larger units. The standards can also be met through other non-BSER options, 

such as natural gas co-firing.

Stationary combustion turbines.

The final rule establishes standards of performance for newly constructed and 

reconstructed stationary combustion turbines. The EPA is finalizing separate standards for base 

load units and non-base load units, as well as a sliding scale approach for deriving the unit 

specific, capacity factor threshold above which a combustion turbine transitions from the 

subcategory for non-base load units to the subcategory for base load units.

For newly constructed and reconstructed base load natural gas-fired stationary

combustion turbines, the EPA is finalizing a standard of 1,000 lb CO2/MWh-gross based on 

efficient NGCC technology as the BSER. Alternatively, owners and operators of base load 

natural gas-fired combustion turbines may elect to comply with a standard based on net output 

(1,030 lb CO2/MWh-net).

For newly constructed and reconstructed natural gas-fired non-base load stationary

combustion turbines, the EPA is finalizing the BSER as combustion of clean fuels (natural gas 

with a small allowance for distillate oil) and a corresponding heat input based standard of 

120 lb CO2/MMBtu. This standard of performance will apply to the vast majority of simple cycle 

combustion turbines. The EPA is finalizing a heat input based clean fuels standard because we 

have insufficient information to set a uniform output-based standard that can be achieved by all 

new nominal peaking units.

In addition, for newly constructed and reconstructed multi-fuel-fired4stationary

combustion turbines, the EPA is finalizing an input-based standard of 120 to 160 lb CO2/MMBtu 

based on the combustion of clean fuels as the BSER. The EPA has similarly determined that it 

has insufficient information at this time to set a uniform output-based standard for stationary

combustion turbines that operate with significant quantities of a fuel other than natural gas.

The EPA is withdrawing the proposed standards and is subsequently not promulgating 

final standards of performance for modified combustion turbines. As we indicated in the 

proposal, sources from the power sector have notified the EPA of very few NSPS modifications, 

 

4

The term "multi-fuel-fired" refers to a stationary combustion turbine that is physically 

connected to a natural gas pipeline but that burns a fuel other than natural gas for 10 percent or 

more of the unit's heat input capacity during the 12-operating month compliance period.
6

and we expect that there will be few NSPS modifications for GHG emissions as well. Our 

decision to eliminate the subcategories for small and large EGUs and set a single standard of 

1,000 lb CO2/MWh-g has raised questions as to whether smaller existing combustion turbines 

that undertake a modification can meet this standard. As a result, we have concluded that it is

prudent to delay issuing standards for sources that undertake modifications.

Requirements and Potential Respondents

In general, all CAA section 111 standards require notifications, reports, and records that 

are essential in determining compliance, and are required of all sources subject to the standards.

The final rule will impose minimal new information collection burden on affected sources

beyond what those sources would already be subject to under the authorities of CAA parts 75 

(Acid Rain Program CEM requirements) and 98 (Mandatory GHG Reporting, applicable to 

EGUs that capture CO2). OMB has previously approved the information collection requirements 

contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR part 98) under 

the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB 

control numbers 2060-0626 and 2060-0629, respectively. Apart from certain reporting costs to 

comply with the emission standards under the rule, there are no new information collection costs, 

as the information required by the rule is already collected and reported by other regulatory 

programs.

Potential respondents are owners and operators of newly constructed, modified, and 

reconstructed fossil fuel-fired EGUs meeting the applicability requirements specified in the final 

rule. The rule regulates emissions of CO2 and requires CEMS to measure CO2 concentration, 

stack gas flow rate, and (if needed) stack gas moisture content in accordance with 40 CFR part 

75 in order to determine hourly CO2 mass emissions rates (tons/hour). The rule allows owners or 

operators of EGUs that burn exclusively gaseous or liquid fuels to install fuel flow meters as an 

alternative to CEMS. To implement this alternative, hourly measurements of fuel flow rate and 

periodic determinations of the gross calorific value (GCV) of the fuel are also required. The rule 

requires that hourly unit operating time and gross output be monitored. The initial performance 

compliance demonstration consists of calculating the CO2 mass emissions rate using the first 12 

operating months of data (hourly CO2 average concentration, mass flow rate, and electrical 

power generation), starting with the first operating month after the calendar month in which 

emissions reporting is required to begin. Compliance with the applicable average CO2 mass 

emissions rate (lb/MWh) is calculated as a 12-operating-month rolling average basis, updated 

after each new operating month, using the reported hourly CO2 average concentration and flow 

rate values from the certified CEMS data collected for the previous month’s process operating 

days along with generation data tracked by the facility for the unit. The final rule specifies that 

the owner or operator of a newly constructed, modified, or reconstructed unit is required to

comply with the notification, reporting, and recordkeeping requirements, as applicable, in the 

section 111 regulatory general provisions(40 CFR part 60, subpart A), in 40 CFR part 75, and in 

40 CFR part 98. Owners or operators must record hourly average CO2 emissions concentration, 

hourly average flow rate, unit operating time, and gross electric generation, and keep records of 

calculations performed in determining compliance. As part of an Agency-wide effort to facilitate 

reporting of environmental data and reports, the rule requires that owners and operators subject 

to this regulation must electronically submit quarterly emissions summary reports that include 
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excess emissions and continuous monitoring systems performance data. Any owner or operator 

subject to the provisions subpart TTTT is required to keep each record for 3 years.

The EPA believes that electric power companies will choose to build new EGUs that 

comply with the regulatory requirements of the rule, even in the absence of the rule, because of 

existing and expected market conditions. The EPA does not project any new coal-fired EGUs 

that commenced construction after the January 2014 proposal to commence operation over the 3-

year period covered by this ICR. We estimate that 12 newly constructed affected NGCC units 

and 25 newly constructed affected natural gas-fired simple cycle CT units would commence 

operation during that time period.5 As a result of the final rule, owners or operators of those units 

will be required to prepare quarterly emissions summary reports.

Over the history of the NSPS program, the EPA has only received notice that a few 

EGUs have triggered the modification provisions of CAA section 111. In addition, over the 

lengthy history of the NSPS program, the EPA is only aware of one EGU that has triggered the 

reconstruction provisions of CAA section 111. Based on this information, the EPA expects few 

EGUs will take actions that would constitute modifications or reconstructions as defined under 

the EPA’s NSPS regulations. Although not anticipated, if an EGU were to modify or reconstruct

during the 3-year period covered by this ICR, the owner or operator of the EGU would be 

required to prepare quarterly emissions summary reports.

2. Need for and Use of the Collection

(a) Need/Authority for the Collection

The EPA is charged under section 111 of the CAA to establish standards of performance 

for new, modified, and reconstructed stationary sources that reflect:

. . . application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction and any 

non-air quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately 

demonstrated. Section 111(a)(l).

In addition, CAA section 114(a) states that the Administrator may require any owner or 

operator subject to any requirement of this Act to:

(A) Establish and maintain such records; (B) make such reports; 

(C) install, use, and maintain such monitoring equipment, and use 

such audit procedures, or methods; (D) sample such emissions (in 

accordance with such procedures or methods, at such locations, at 

such intervals, during such periods, and in such manner as the 

Administrator shall prescribe); (E) keep records on control 

 

5

Estimates are based on (1) "EPA Base Case v.5.15 using IPM" projections for new capacity

builds of 2,349 MW of new NGCC capacity and 2,002 MW of new natural gas simple cycle CT 

capacity over the 2016-2018 period and (2) unit capacities of 200 MW for new NGCC units and 

80 MW for new natural gas-fired simple cycle CT units.
8

equipment parameters, production variables or other indirect data 

when direct monitoring of emissions is impractical; (F) submit 

compliance certifications in accordance with section 114(a)(3); and 

(G) provide such other information as the Administrator may

reasonably require.

As previously stated, the EPA in 2009 found that by causing or contributing to climate 

change, GHGs endanger both the public health and the public welfare of current and future 

generations. Fossil fuel-fired power plants are the country’s largest stationary source emitters of 

GHGs. Therefore, NSPS for emissions of CO2 are being established for this category of sources 

at 40 CFR part 60, subpart TTTT.

Certain records and reports are necessary for the Administrator to: 1) identify newly

constructed, modified, and reconstructed EGUs subject to the standards, 2) ensure that the NSPS 

is being properly applied; 3) identify those facilities that should be inspected; 4) identify those 

facilities that may benefit from compliance assistance activities; and 5) ensure that process and 

emissions control/monitoring equipment are being properly operated and maintained on a 

continuous basis.

(b) Use/Users of the Data

The required information will be used by agency enforcement personnel to ensure that 

the emission limitations are being achieved. Based on review of the recorded information at the 

site and the reported information, the EPA can identify facilities that may not be in compliance 

and decide which plants, records, or processes should be inspected.

3. Nonduplication, Consultations, and Other Collection Criteria

(a) Nonduplication

As previously stated, the final rule will impose minimal new information collection 

burden on affected sources beyond what those sources would already be subject to under the 

authorities of CAA parts 75 and 98. Apart from certain reporting costs to comply with the 

emission standards under the rule, there are no new information collection costs, as the 

information required by the rule is already collected and reported by other regulatory programs.

The rule requires that affected owners or operators follow the applicable reporting requirements 

and submit reports as required by the other regulatory programs. Therefore, no duplication exists. 

(b) Public Notice Required Prior to ICR Submission to OMB

This section is not applicable because this is a rule-related ICR.

(c) Consultations

The EPA has engaged extensively with a broad range of stakeholders and the general 

public regarding climate change, carbon pollution from power plants, and carbon pollution 

reduction opportunities. These stakeholders included industry and electric utility representatives, 

state and local officials, tribal officials, labor unions and non-governmental organizations.

Early in the process of developing carbon pollution standards for new power plants, the 

EPA held five listening sessions in February and March 2011 to obtain information and input 
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from key stakeholders and the public. Each of the five sessions had a particular target audience; 

these were the electric power industry, environmental and environmental justice organizations, 

states and Tribes, coalition groups and the petroleum refinery industry.

The EPA has conducted subsequent outreach sessions – the vast majority of which 

occurred between September 2013 and November 2013. The agency held 11 public listening 

sessions; one national listening session in Washington, DC and 10 listening sessions in locations 

across the country. In addition to the 11 public listening sessions, direct engagement has included 

hundreds of meetings with individual stakeholder groups, and meetings that brought together a 

variety of stakeholders to discuss a wide range of issues related to the electricity sector and 

regulation of GHGs under the CAA. The agency provided and encouraged multiple opportunities 

to engage with each one of the 50 states. The agency met with electric utility associations and 

electricity grid operators. Agency officials have engaged with labor unions and with leaders 

representing large and small industries. Because of the focus of the standard on the electricity

sector, many of the EPA’s meetings with industry have been with utilities and industry

representatives directly related to the electricity sector. The agency has also met with energy

industries such as coal and natural gas interests. In addition, the agency has met with companies 

that offer new technology to prevent or reduce carbon pollution, including companies that 

represent renewable energy and energy efficiency interests. The EPA has also met with 

representatives of energy intensive industries such as the iron and steel, and aluminum industry

to help understand the issues related to large industrial purchasers of electricity. Agency officials 

engaged with representatives of environmental justice organizations, environmental groups and 

religious organizations.

In light of the interest among governmental entities, the EPA initiated consultations with 

governmental entities while formulating the provisions of the proposed standards for new EGUs. 

Although only new EGUs would be affected by those proposed standards, the outreach regarded 

planned actions for new, reconstructed, modified and existing sources. On April 12, 2011, the 

EPA engaged with the following 10 national organizations representing state and local elected 

officials: (1) National Governors Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) 

National Association of Counties, (7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County Executives of America, and (10) 

Environmental Council of States. On February 26, 2014, the EPA re-engaged with those 

governmental entities to provide a pre-proposal update on the emission guidelines for existing 

EGUs and emission standards for modified and reconstructed EGUs.

In light of the interest among tribal entities, the EPA conducted outreach to tribal 

environmental staff and offered consultation with tribal officials in developing the standards. 

Because the EPA is aware of tribal interest in carbon pollution standards for the power sector, 

prior to proposal of GHG standards for new power plants, the EPA offered consultation with 

tribal officials early in the process of developing the proposed regulation to permit them to have 

meaningful and timely input into its development. The EPA’s consultation regarded planned 

actions for new, reconstructed, modified, and existing sources. A consultation/outreach meeting 

was held on May 23, 2011. In this meeting, the EPA provided background information on the 

GHG emission standards to be developed and a summary of issues being explored by the 
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Agency. The EPA also held a series of listening sessions prior to proposal of GHG standards for 

new power plants. Tribes participated in a session on February 17, 2011, with the state agencies, 

as well as in a separate session with tribes on April 20, 2011.

During development of the regulation, consultation letters were sent to 584 tribal leaders. 

The letters provided information regarding the EPA’s development of both the NSPS for 

modified and reconstructed EGUs and emission guidelines for existing EGUs and offered 

consultation. None have requested consultation. Tribes were invited to participate in the national 

informational webinar held August 27, 2013. In addition, a consultation/outreach meeting was 

held on September 9, 2013, with tribal representatives from some of the 584 tribes. The EPA 

also met with tribal environmental staff with the National Tribal Air Association, by

teleconference, on July 25, 2013, and December 19, 2013. In those teleconferences, the EPA 

provided background information on the GHG emission guidelines to be developed and a 

summary of issues being explored by the agency.

(d) Effects of Less Frequent Collection

If the relevant information were collected less frequently, the EPA would not be 

reasonably assured that a power plant is in compliance with the standards.

(e) General Guidelines

None of the guidelines in 5 CFR 1320.5 are being exceeded.

(f) Confidentiality

All information submitted to the agency for which a claim of confidentiality is made will 

be safeguarded according to the agency policies set forth in Title 40, Chapter 1, part 2, subpart 

B–Confidentiality of Business Information (see 40 CFR 2; 41 FR 36902, September 01, 1976; 

amended by 43 FR 39999, September 28, 1978; 43 FR 42251, September 28, 1978; 44 FR 

17674, March 23, 1979).

(g) Sensitive Questions

This section is not applicable because this ICR does not involve matters of a sensitive 

nature.

4. The Respondents and the Information Requested

(a) Respondents/NAICS Codes

Respondents are owners or operators of new, modified, and reconstructed fossil fuel-fired

EGUs. All respondents would be subject to the monitoring, recordkeeping, and reporting 

requirements. The applicable NAICS codes are 221112, Fossil fuel electric power generating 

units (covers owners/operators of industry or federal, state or local government establishments),

and 921150, Fossil fuel electric power generating units in Indian Country.
11

(b) Information Requested

(i) Data Items, Including Recordkeeping Requirements. 

Apart from certain reporting costs to comply with the emission standards under the rule, 

there are no new information collection costs, as the information required by the rule is already

collected and reported by other regulatory programs (CAA parts 75 and 98). The EPA does not 

project any new coal-fired EGUs that commenced construction after the January 2014 proposal 

to commence operation over the 3-year period covered by this ICR. We estimate that 12 newly 

constructed affected NGCC units and 25 newly constructed affected natural gas-fired simple 

cycle CT units will commence operation during that time period. As a result of the final rule, 

owners or operators of those units will be required to prepare quarterly emissions summary

reports. Although not anticipated, if an EGU were to modify or reconstruct during the 3-year 

period covered by this ICR, the owner or operator of the EGU would be required to prepare 

quarterly emissions summary reports.

(ii) Respondent Activities.

The respondent activities required by the NSPS are introduced in section 6(a).

The EPA estimates that 12 newly constructed affected NGCC units and 25 newly

constructed affected natural gas-fired simple cycle CT units will commence operation over the 3-

year period covered by this ICR and expects few EGUs will take actions that would constitute 

modifications or reconstructions as defined under the EPA’s NSPS regulations during that time 

period.

(iii) Electronic Reporting. 

Owners and operators with EGUs subject to this regulation must electronically submit 

quarterly emissions summary reports of emissions and continuous monitoring systems 

performance. Owners or operators would need to submit these reports to the EPA using the 

Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean 

Air Markets Division in the EPA Office of Atmospheric Programs.

5. The Information Collected: Agency Activities, Collection Methodology, and 

Information Management

(a) Agency Activities

There would be no EPA burden associated with the reporting requirements of the 

standards. As a result of this regulation, the owners or operators of the 12 newly constructed 

affected NGCC units and 25 newly constructed affected natural gas-fired simple cycle CT units 

that we estimate will commence operation during the 3-year period of the ICR will be required to 

electronically submit a quarterly summary report, which includes reporting emissions and 

downtime. Similarly, if an EGU were to modify or reconstruct, the owner or operator of the 

affected EGU would be required to electronically submit a quarterly summary report, which 

includes reporting emissions and downtime. The fees for upkeep of this electronic database are 

already funded through other rules. Thus, there would be no burden to the agency associated 

with these reporting requirements.
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(b) Collection Methodology and Management

Following notification of startup, the reviewing authority might inspect the source to 

determine whether the CO2 CEMS and the associated automatic data acquisition system are 

properly installed and operated. Performance test reports are used by the agency to discern a 

source’s initial capability to comply with the emission standard. Data and records maintained by

the respondents are used in compliance and enforcement programs. The quarterly reports are 

used for problem identification, as a check on source operation and maintenance, and for 

compliance determinations.

The information obtained is then entered into the Air Facility Subsystem (AFS) which is 

operated and maintained by the EPA’s Office of Compliance. AFS is the EPA’s database for the 

collection, maintenance, and retrieval of compliance and annual emission inventory data for over 

125,000 industrial and government owned facilities. The EPA uses the AFS for tracking air 

pollution compliance and enforcement by local and state regulatory agencies, EPA regional 

offices and EPA headquarters. The EPA and its delegated Authorities can edit, store, retrieve, 

and analyze the data.

Any owner or operator subject to the provisions of this subpart will be required to keep 

each record for 3 years following the date of each occurrence, measurement, maintenance, 

corrective action, report, or record. Each record must be kept on site for at least 2 years after the 

date of each occurrence, measurement, maintenance, corrective action, report, or record. 60.7. 

Records that are accessible from a central location by a computer or other means that instantly

provide access at the site meet this requirement. The records may be kept off site for the 

remaining year. All electronic reports are sent to the EPA using the ECMPS Client Tool. All 

non-electronic reports are sent to the delegated state or local authority. In the event that there is 

no such delegated authority, the reports are sent directly to the U.S. EPA regional office. 

(c) Small Entity Flexibility

The EPA is aware that there is substantial interest in the rule among small entities 

(municipal and rural electric cooperatives). The EPA has conducted an unprecedented amount of 

stakeholder outreach. As part of that outreach, agency officials participated in many meetings 

with individual utilities as well as meetings with electric utility associations. Specifically, the 

EPA Administrator, Gina McCarthy, participated in separate meetings with both the National 

Rural Electric Cooperative Association (NRECA) and the American Public Power Association 

(APPA). The meetings brought together leaders of the rural cooperatives and public power 

utilities from across the country. The Administrator discussed and exchanged information on the 

unique challenges, in particular the financial structure, of NRECA and APPA member utilities.

In addition, the EPA conducted outreach to representatives of small entities while 

formulating the provisions of the proposed standards of performance for new EGUs. Although 

only new EGUs would be affected by those proposed standards, the outreach regarded planned 

actions for new, reconstructed, modified and existing sources. The EPA conducted outreach with 

representatives from 20 various small entities that potentially would be affected by GHG 

standards. The representatives included small entity municipalities, cooperatives, and private 

investors. We met with eight of the small entity representatives, as well as three participants 

from organizations representing power producers, on June 17, 2011, to discuss the outreach 

materials (background, an overview of affected sources and GHG emissions from the power 
13

sector, an overview of CAA section 111, an assessment of CO2 emissions control technologies, 

and potential impacts on small entities), potential requirements of the rule, and regulatory areas 

where the EPA has discretion and could potentially provide flexibility.

A second outreach meeting was conducted on July 13, 2011. We met with nine of the 

small entity representatives, as well as three participants from organizations representing power 

producers. During the second outreach meeting, various small entity representatives and 

participants from organizations representing power producers presented information regarding 

issues of concern with respect to development of standards for GHG emissions.

(d) Collection Schedule

The specific frequency for each information collection activity within this request is 

shown in Exhibits 1a, 1b, and 1c for the first 3 years following promulgation of the standards.

6. Estimating the Burden and Cost of the Collection

Exhibit 1a, Exhibit 1b, and Exhibit 1c document the computation of individual burdens 

for the reporting requirements applicable to the industry for the subpart included in this ICR for 

each of the first 3 years. Table 2 contains a summary of the respondent burden hours and costs 

detailed in Exhibit 1a, Exhibit 1b, and Exhibit 1c.

Table 2. Summary of Respondent Burden and Costs

Year Total Annual Labor Burden (hours) Total Annual Labor Costs ($)

1 460 44,652

2 620 58,014

3 872 80,265

Total 1952 182,931

3-Year Average 651 60,977

The individual burdens are expressed under standardized headings believed to be 

consistent with the concept of burden under the Paperwork Reduction Act. Where appropriate, 

specific tasks and major assumptions have been identified; responses to this information 

collection are mandatory.

The agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB Control Number.

(a) Estimating Respondent Burden

The average annual burden to industry over the 3-year period of this ICR from these 

reporting requirements is estimated to be 651 hours per year (detailed in Exhibit 1d). These hours 

are based on agency studies and background documents from the development of the regulation, 

agency knowledge, and experience with the NSPS program.
14

(b) Estimating Respondent Costs

Respondent costs are typically divided into three categories. These categories include 

labor costs, operations and maintenance (O&M) costs, and annualized capital costs. Labor costs 

are the only respondent costs associated with this ICR. 

(i) Estimating Labor Costs

The average annual labor costs to industry over the 3-year period of this ICR from these 

reporting requirements is estimated to be $60,978 per year (detailed in Exhibit 1d). Labor rates 

and associated costs are based on Bureau of Labor Statistics (BLS) data. Technical, managerial,

and clerical average hourly rates for private industry workers were based on the BLS, 

Occupational Employment Statistics, May 2013 National Industry-Specific Occupational 

Employment and Wage Estimates for NAICS 221100 - Electric Power Generation, Transmission 

and Distribution (part of NAICS 221000 – Utilities). The approximate labor rates are $40.03 per 

hour for technical (architecture and engineering occupations), $59.44 per hour for managerial

(management occupations), and $22.49 per hour for clerical (office and administrative support 

occupations). The labor rates from BLS were multiplied by an overhead multiplier of 110 

percent to estimate loaded labor rates of $84.06 per hour for technical, $124.82 per hour for 

managerial, and $47.23 per hour for clerical.

(ii) Estimating Annualized Capital Costs

There are no annualized capital costs associated with this ICR.

(iii) Estimating O&M Costs

There are no annual O&M costs associated with this ICR.

(c) Estimating Agency Burden and Cost

Because the information collection requirements were developed as an incidental part of 

standards development, no costs can be attributed to the development of the information 

collection requirements. Because reporting and recordkeeping requirements on the part of the

respondents are required under the part 60 General Provisions, no operational costs will be 

incurred by the Federal Government. Publication and distribution of the information are part of 

the Compliance Data System, with the result that no Federal costs can be directly attributed to 

the ICR. Examination of records to be maintained by the respondents will occur incidentally as 

part of the periodic inspection of sources that is part of the EPA's overall compliance and 

enforcement program, and, therefore, is not attributable to the ICR. The only costs that the 

Federal government could incur are user costs associated with the analysis of the reported 

information. The Federal government would not incur those costs as a result of these standards.

(d) Estimating the Respondent Universe and Total Burden and Costs.

The EPA estimates that 12 newly constructed NGCC units and 25 newly constructed

natural gas-fired simple cycle CT units will become subject to the regulation over the 3-year 

period of the ICR. Although not anticipated, if an EGU were to modify or reconstruct over the 3-

year period of the ICR, it would become subject to the regulation.
15

The total annual number of responses for the new monitoring, recordkeeping, and 

reporting requirements in subpart TTTT over the 3-year ICR period is estimated to be 280. The 

average number of annual responses over the 3-year ICR period is 93.3 per year.

The annual public reporting and recordkeeping burden for this collection of information 

is estimated to average 7 hours per response. Average annual responses per respondent are 

estimated to be 4.5. The total annual labor burden over the 3-year ICR period is estimated to be 

1,952 person hours. The average annual labor burden for the rule is estimated to be 651 person 

hours per year.

The total annual labor costs over the 3-year ICR period are estimated at $182,931. The 

average annual labor costs to industry over the 3-year period of this ICR are estimated to be 

$60,977 per year.

(e) Bottom Line Burden Hours and Cost Tables

There are no annualized capital costs or O&M costs associated with this ICR. The bottom 

line labor hours and costs burden for each year of the 3-year ICR period appear in Exhibit 1a, 

Exhibit 1b, and Exhibit 1c.

(f) Reasons for Change in Burden.

The increase in burden is due to this being a new ICR that estimates burden associated 

with standards for newly constructed, modified, and reconstructed EGUs.

(g) Burden Statement

The average annual labor-hour burden for the rule is estimated to be 651 person hours per 

year and the average annual labor costs are estimated to be $60,977 per year. Average annual 

labor-burden per respondent is estimated to be 31.5 person hours per year and average annual 

labor costs per respondent are estimated to be $2,946 per year. There are no annualized capital 

costs or annual O&M costs associated with this ICR. Burden means the total time, effort, or 

financial resources expended by persons to generate, maintain, retain, or disclose or provide 

information to or for a Federal agency. This includes the time needed to review instructions; 

develop, acquire, install, and utilize technology and systems for the purposes of collecting, 

validating, and verifying information, processing and maintaining information, and disclosing 

and providing information; adjust the existing ways to comply with any previously applicable 

instructions and requirements; train personnel to be able to respond to a collection of 

information; search data sources; complete and review the collection of information; and 

transmit or otherwise disclose the information.

An agency may not conduct or sponsor, and a person is not required to respond to a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA’s regulations in 40 CFR part 60 are listed in 40 CFR part 9.

PART B

This section is not applicable because statistical methods are not used in data collection 

associated with the final amendments
16

Exhibit 1a. Year 1 Respondent Burden and Cost of Reporting and Recordkeeping Requirements, NSPS for GHG Emissions 

for Newly Constructed, Modified, and Reconstructed EGUs (40 CFR part 60, subpart TTTT)

Burden Item (A)

Hours per 

Occurrence

(B) Occurrences/ 

Respondent/Year

(C)

Hours/ 

Respondent/ 

Year (A x 

B)

(D) 

Respondents/ 

Yeara

(E)

Total 

Hours/ 

Year

(C x D)

(E) 

Technical 

Hours/Year

(E x .79)

(F)

Managerial 

Hours/Year

(E x .09)

(G)

Clerical 

Hours/Year

(E x .12) 

(H)

Cost/ 

Year

REPORTING REQUIREMENTS

Read and Understand Rule Requirements b30 1 30 10 300 150 150 0 31,332

Prepare/Submit Emissions Summary Report

Includes reporting of excess emissions & 

downtime 4 4 16 10 160 127 14 19 13,320

TOTAL ANNUAL LABOR BURDEN AND 

COST 460 277 164 19 44,652

a

Includes 10 respondents (2 combined cycle CT facilities and 8 simple cycle CT units) that become subject to NSPS requirements for newly constructed EGUs beginning in Year 

1. Each combined cycle CT facility is assumed to have two 200 MW CT units.

b Assumes one-time burden of 30 hours (based on an average reading rate of 100 words/minute) to read and understand rule requirements, divided equally among technical and 

managerial staff.
17

Exhibit 1b. Year 2 Respondent Burden and Cost of Reporting and Recordkeeping Requirements, NSPS for GHG Emissions 

for Newly Constructed, Modified, and Reconstructed EGUs (40 CFR part 60, subpart TTTT)

Burden Item (A)

Hours per 

Occurrence

(B) Occurrences/ 

Respondent/Year

(C)

Hours/ 

Respondent/ 

Year (A x 

B)

(D) 

Respondents/ 

Year

(E)

Total 

Hours/ 

Year

(C x D)

(E) 

Technical 

Hours/Year

(E x .79)

(F)

Managerial 

Hours/Year

(E x .09)

(G)

Clerical 

Hours/Year

(E x .12) 

(H)

Cost/ 

Year

REPORTING REQUIREMENTS

Read and Understand Rule Requirements a30 1 30 10b300 150 150 0 31,332

Prepare/Submit Emissions Summary Report

Includes reporting of excess emissions & 

downtime 4 4 16 20

c

320 253 29 38 26,682

TOTAL ANNUAL LABOR BURDEN AND 

COST 620 403 179 38 58,014

a Assumes one-time burden of 30 hours (based on an average reading rate of 100 words/minute) to read and understand rule requirements, divided equally among technical and 

managerial staff.

b

Includes 10 respondents (2 combined cycle CT facilities and 8 simple cycle CT units) that become subject to NSPS requirements for newly constructed EGUs beginning in Year 

2. Each combined cycle CT facility is assumed to have two 200 MW CT units.

c

Includes 10 respondents (2 combined cycle CT facilities and 8 simple cycle CT units) that become subject to NSPS requirements for newly constructed EGUs beginning in Year 

2 and 10 respondents (2 combined cycle CT facilities and 8 simple cycle CT units) that are already subject to NSPS requirements for newly constructed EGUs (i.e., became subject 

in Year 1). Each combined cycle CT facility is assumed to have two 200 MW CT units.
18

Exhibit 1c. Year 3 Respondent Burden and Cost of Reporting and Recordkeeping Requirements, NSPS for GHG Emissions 

for Newly Constructed, Modified, and Reconstructed EGUs (40 CFR part 60, subpart TTTT)

Burden Item (A)

Hours per 

Occurrence

(B) Occurrences/ 

Respondent/Year

(C)

Hours/ 

Respondent/ 

Year (A x 

B)

(D) 

Respondents/ 

Year

(E)

Total 

Hours/ 

Year

(C x D)

(E) 

Technical 

Hours/Year

(E x .79)

(F)

Managerial 

Hours/Year

(E x .09)

(G)

Clerical 

Hours/Year

(E x .12) 

(H)

Cost/ 

Year

REPORTING REQUIREMENTS

Read and Understand Rule Requirements a30 1 30 12

b

360 180 180 0 37,598

Prepare/Submit Emissions Summary Report

Includes reporting of excess emissions & 

downtime 4 4 16 32c512 405 46 61 42,667

TOTAL ANNUAL LABOR BURDEN AND 

COST 872 585 226 61 80,265

a Assumes one-time burden of 30 hours (based on an average reading rate of 100 words/minute) to read and understand rule requirements, divided equally among technical and 

managerial staff.

b

Includes 11 respondents (2 combined cycle CT facilities and 9 simple cycle CT units) that become subject to NSPS requirements for newly constructed EGUs beginning in Year 

3 and 1 respondent that becomes subject to NSPS requirements for modified/reconstructed EGUs beginning in Year 3. Each combined cycle CT facility is assumed to have two 

200 MW CT units.

c

Includes 11 respondents (2 combined cycle CT facilities and 9 simple cycle CT units) that become subject to NSPS requirements for newly constructed EGUs beginning in Year 

3; 1 respondent that becomes subject to NSPS requirements for modified/reconstructed EGUs beginning in Year 3; and 20 respondents (4 combined cycle CT facilities and 16

simple cycle CT units) that are already subject to NSPS requirements for newly constructed EGUs (i.e., became subject in Year 1 or Year 2). Each combined cycle CT facility is 

assumed to have two 200 MW CT units.
19

Exhibit 1d. Summary of Respondent Burden and Cost of Reporting and Recordkeeping Requirements, NSPS for GHG 

Emissions for Newly Constructed, Modified, and Reconstructed EGUs (40 CFR part 60, subpart TTTT)

Summary of Respondent Burden and Cost

Totals Annual Labor 

Burden (Hours)

Annual

Labor Costs

Annualized

Capital Costs

Annual

O&M Costs Annualized Costs

3-Year Total 1,952 $182,931 $0 $0 $0

Average Annual 651 $60,977 $0 $0 $0

Average Annual per 

Respondenta 31.5 $2,946 $0 $0 $0

a Equal to average annual estimate divided by the average annual number of respondents.

Summary of Responses

Information Collection Activity

Occurrence 

per 

Respondent Respondents Total

Responses

Average 

Annual

REPORT REQUIREMENTS

Read and Understand Rule 

Requirements 1 32 32

Prepare/Submit Emissions 

Summary Report 4 62 248

3-Year Total Responses 280

Average Annual Number of Responses = 93.3

Average Annual Number of Respondents = 20.7

Average Annual Responses per Respondent = 4.5

Average Annual Hours per Response = 7