NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FROM COALAND OIL-FIRED ELECTRIC UTILITY STEAM GENERATING UNITS –

RECONSIDERATION OF CERTAIN STARTUP/SHUTDOWN ISSUES;

SUMMARY OF PUBLIC COMMENTS AND RESPONSES

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, North Carolina 27711

November 2014
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THIS PAGE INTENTIONALLY LEFT BLANK
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Contents

1.0 DEFINITIONS AND WORK PRACTICES ........................................................................................ 1

1.1. Definitions........................................................................................................................................ 1

1.1.1 Definition of startup................................................................................................................... 1

1.1.1.1 25 percent plus 3 hours, or generation plus 6 hours ............................................................ 7

1.1.1.3 25 percent plus 7 or 8 hours............................................................................................... 21

1.1.1.4 25 percent plus 7 hours or generation plus 10 hours ......................................................... 22

1.1.1.5 50 percent plus 3 hours or generation plus 9 hours ........................................................... 25

1.1.1.6 Generation plus 12 hours................................................................................................... 25

1.1.1.7 APCD’s in service.............................................................................................................. 25

1.1.1.8 Supercritical EGUs ............................................................................................................ 33

1.1.1.9 CFB EGUs......................................................................................................................... 35

1.1.1.10 Dry FGD EGUs................................................................................................................ 39

1.1.1.11 Use of SO2/NOx Data ...................................................................................................... 47

1.1.1.12 Failed Starts ..................................................................................................................... 50

1.1.1.13 NSPS................................................................................................................................ 53

1.1.1.14 Definition of Startup - Other............................................................................................ 53

1.1.2 Definition of shutdown ............................................................................................................ 59

1.1.2.1 NSPS.................................................................................................................................. 61

1.1.3 Clean fuels ............................................................................................................................... 62

1.2 Work Practices................................................................................................................................ 67

1.2.1 General Support ....................................................................................................................... 67

1.2.2 Not Support Further Changes .................................................................................................. 70

1.2.3 Standard Already Accounts for Variability ............................................................................. 74

1.2.4 Legal issues.............................................................................................................................. 79

1.2.5 Common stack ......................................................................................................................... 84

1.2.6 Allow site-specific standards................................................................................................... 94

1.2.7 Title V, state, or local permitting ............................................................................................. 98

1.2.8 Petition the Administrator........................................................................................................ 99

1.2.9 Flexibility to reflect equipment variability ............................................................................ 100

2.0 CLEAN FUELS................................................................................................................................ 106
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2.1 Oppose .......................................................................................................................................... 111

2.2 Co-firing with other fuels.............................................................................................................. 112

2.3 Edit to standard ............................................................................................................................. 118

3.0 APCD OPERATION ........................................................................................................................ 118

3.1 Startup........................................................................................................................................... 118

3.2 General.......................................................................................................................................... 122

3.3 Multiple APCDs............................................................................................................................ 125

3.4 Acid Gas APCDs .......................................................................................................................... 128

3.4.1 Wet flue gas desulfurization – wet FGD.................................................................................... 128

3.4.2 Dry FGDs and CFBs.................................................................................................................. 128

3.6 Selective catalytic reduction - SCR .............................................................................................. 146

3.7 Selective noncatalytic reduction - SNCR ..................................................................................... 148

3.8 Activated sorbent injection (ACI)/Hg control .............................................................................. 148

3.9 Limestone injection....................................................................................................................... 150

3.10 Shutdown .................................................................................................................................... 151

3.11 Other ........................................................................................................................................... 153

4.0 WORK PRACTICE STANDARDS: TREATMENT OF IGCC...................................................... 154

4.1 Option 1 Flares.............................................................................................................................. 155

4.2 Option 2 Duct Burners.................................................................................................................. 158

5.0 OTHER ............................................................................................................................................. 160

5.1 Use of diluent cap ......................................................................................................................... 164

5.2 Use of default MW value.............................................................................................................. 173

5.3 Sorbent trap monitoring systems .................................................................................................. 177

5.4 Other concerns.............................................................................................................................. 182

5.5 Support for other commenters/comments..................................................................................... 184

5.6 Out of Scope ................................................................................................................................. 184
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1.0 DEFINITIONS AND WORK PRACTICES

1.1. Definitions

1.1.1 Definition of startup

Summary of Comments Received Following November 30, 2012, Proposal

Comment 1: Commenters 20252, 20255, 20257, 20262, 20270, 20271, 20272, 20277, 20279, 20280, 

20281, 20282, 20288, 20291, 20294, 20295, 20306, 20308, and 20321 commented on the proposed 

definition for the end of the startup period. Commenters state that even though an EGU is producing 

electricity or useful steam, that EGU has not necessarily completed startup from an operational 

standpoint. Commenters request that the EPA should modify how it defines startup to allow all emission 

control devices to reach operational effectiveness before startup ends. Commenters note that per the 

EPA’s definition of startup even internally used steam could inaccurately mark the end of the startup and 

thereby terminate applicability of the work practice standards. 

Commenters note that spikes in emissions can occur after the EPA’s defined end of startup. 

Consequently, electric utility steam generating units (EGUs) may have difficulty complying with a 30-

operating day average if the end of startup is tied to electricity generation. Commenters further state that 

the problem will be compounded by the fact that it is possible for the EGUs to startup more than once in 

a single 30-day averaging period, and the need for startups is not predictable. Commenters emphasize 

that the EPA’s definition of “startup” that requires EGUs to begin to measure hazardous air pollutant 

(HAP) emissions does not match with the EPA’s startup work practice standards, , which correctly 

recognize that certain air pollution controls cannot be immediately started without damaging the controls 

or putting plant workers at a safety risk. 

Commenters ask that the determination as to when startup ends should be determined on a unit-by-unit 

basis and placed in a unit-specific startup and shutdown plan. Commenters suggest that if the EPA does 

not want to use a case-by-case approach for determining startup, then the EPA should develop different 

startup definitions based on generation type because of related differences in startup processes. 

Commenters discussed different types of EGUs and provide specific suggestions for startup definitions 

by EGU types including: (1) supercritical EGUs, (2) subcritical EGUs, (3) fluidized bed combustors 

(FBCs), and (4) integrated gasification combined cycle (IGCC) EGUs. Commenters note that these 

definitions should apply unless the owner/operator demonstrates the need for an alternative EGUspecific “startup” because of unique EGU conditions. In that case, the permitting authority would 

approve an alternative definition in the EGU’s Title V permit. 

Some commenters ask that the EPA apply the Part 63 General Provisions definitions of “startup” and 

“shutdown” to subpart UUUUU. Others recommend that the Mercury and Air Toxics Standards 

(MATS) be revised to specify that EGUs have a startup plan incorporated into its Part 70 permit. A 

commenter states that for EGUs that select the site-specific option, startup/shutdown (SS) plans would 

allow owners and operators to determine when startup and shutdown begins and ends based on 

parameters that are easily monitored at that EGU. Commenter further state that these parameters could 

be based on requirements in other rules to which EGUs are already subject. Commenter notes that as an 

example, EGUs subject to the Acid Rain Program are already required to define the EGU’s ranges of 
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operation and normal load (see 40 CFR Part 75, Appendix A, section 6.5.2.1). Commenters state that 

startup and shutdown for such EGUs could easily be based on these ranges of operation.

A commenter states that allowing EGUs the option to develop SS plans would avoid potential conflicts 

between the MATS and other applicable requirements, would regulate SS more efficiently than applying 

multiple, overlapping SS requirements, and would reduce unnecessary administrative burdens on 

regulated sources. Commenters urged the EPA to allow EGUs to elect to either follow the proposed 

definitions of startup and shutdown, or to follow an individualized SS plan.

Individual comments are as follows.

Commenter 20288 recommends that the definition of startup be revised to provide that startup does not 

end until all emissions control devices for a particular EGU reaches operational effectiveness.

Commenter 20269 notes that the generation of electricity is not always the optimal time to begin using 

air pollution control equipment.

Commenter 20282 recommends that the EPA should modify the definition of “startup” to allow all 

emission control devices to reach operational effectiveness before “startup” ends. Commenter provides

discussion about the incentives EGUs have to exit startup as quickly as possible. 

Commenters 20255, 20281, 20282, and 20295 state that ending “startup” when electricity is first 

produced does not account for the time needed to set the boiler and its associated air pollution control 

equipment into operation, and that electricity production and startup typically overlap.

Commenter 5803 agreed with the proposed language defining startup and shutdown. Commenter states

that the confusion of whether it is the use of steam or the generation of electricity that ends the startup 

period is adequately addressed in the reconsideration. Commenter agreed with similar references to 

steam use that are proposed to be removed from the definition of shutdown events. 

Commenter 20291 states that the EPA should modify how it defines startup to allow all emission control 

devices to reach operational effectiveness before startup ends. Commenter suggests that the definition 

should reflect the length of time actually needed to set an EGU into operation. 

Commenter 20308 states that for existing sources, the work practice must be clear that the end of startup

occurs when conditions meet a minimum level that is associated with the pollution control equipment 

and method utilized.

Commenter 20255 states that emission control systems do not reach optimal performance when either 

electricity or steam is first produced. Commenter states that the definition of startup must take into 

account the limits of control equipment to meet the emission limits and EGUs must be permitted to ramp 

up their operations (temperature, flow, velocity, chemistry) to the point pollution control equipment may 

be effectively engaged. Commenter listed nine main steps (supplemental fuel fire; steam usage; coal 

fire; ESP energized; unit online (i.e., selling electricity to the grid); scrubber in service; SCR inlet 

opening (ready for ammonia injection once the appropriate temperature is reached); ammonia flow for 

the SCR; 25 percent load) that occur during startup, with the EGU online and selling electricity as step 
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five. Commenter states that control systems must be phased in during startup according to their unique 

time, temperature and pressure requirements. Commenter states that the EPA regulations must be clear 

that the end of startup occurs when conditions meet minimum levels specific to the pollution control 

equipment and methods used.

Commenter 20277 states that controls will not be fully functional when the EPA defines startup as 

ending. Commenter states that electricity production and startup are not by definition distinct modes,

and instead typically overlap. Commenter provides examples to highlight this point. Commenter urged 

the EPA to modify “startup” to provide additional time to allow all emission control devices to reach 

operational effectiveness before “startup” ends so that the definition reflects the actual length of time 

needed to set an EGU and its associated control devices into operation.

Commenter 20291 states that ending startup when electricity is first produced does not account for the 

time needed to set into operation the boiler and associated pollution control equipment. Commenter

states that the EPA fails to recognize that electricity production and startup are not by definition distinct 

modes, and typically overlap. According to commenter, electricity generation can begin when a boiler’s 

steam load is less than 10 percent, at which point startup fuel is still being burned, alone or in 

combination with coal, and major components of the EGU, including air pollution controls, are neither 

online nor fully functioning. 

Commenter 20291 states that although the EPA has recognized the operational constraints of pollution 

control equipment during startup, the Agency fails to recognize that those controls will not be fully 

functional when the EPA defines startup as ending. As a result, commenter notes that spikes in 

emissions can occur after the EPA’s defined end of startup. 

Commenter 20294 states that the EPA should more clearly define that period of time when compliance 

monitoring begins and ends for coal-fired EGUs. Commenter states that, as written, the definitions of 

startup and shutdown do not reflect the temporary and transient operating conditions that exist to ensure 

the safe and reliable transition from shutdown to normal operation. Commenter states that even 

internally used steam could inaccurately mark the end of the startup and thereby terminate applicability 

of the work practice standards.

Commenters 20257, 20262, 20270, 20271, and 20321 state that the EPA’s determination that startup 

ends when an EGU generates electricity or makes useful thermal heat is not an appropriate cutoff for 

startup. Each of the commenters provides discussion about the processes leading up to electricity 

generation and the processes after that point. Commenters discussed the engineering and safety issues of 

the process.

Commenter 20257 states that the boiler is not fully finished with startup until all available cyclones are 

online, which could take 20 hours or more for a normal startup.

Commenter 20262 suggests defining the end of startup for subcritical coal-fired EGUs as 4 hours after 

25 percent load is first reached, or 12 hours after first electricity generation, whichever occurs first. 

Commenter states that the 4-hour timeframe would provide for a transition period to complete primary 

fuel firing and bring in emission control equipment safely. Commenter states that the 12-hour alternative 
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definition is designed to cover situations where the startup sequence is delayed for unexpected reasons, 

but still provides assurance that an EGU will not idle at low load.

Commenters 20281 and 20282 recommend that the EPA set a bright line test for defining the startup of a 

supercritical EGU as the transition point from subcritical mode to supercritical mode plus 6 hours and 

for subcritical (i.e., conventional drum) EGUs, the startup period should end 4 hours after 25 percent 

load is first reached, or 12 hours after first electricity generation, whichever occurs first. For FBC EGUs, 

Commenter 20282 recommends the startup period should end 4 hours after 25 percent load is first 

reached, or 12 hours after first electricity generation, whichever occurs first.

Commenter 20270 states that during the period of bringing control equipment to normal operating 

conditions, the equipment may operate far from its design conditions and emissions may be 

unpredictable.

Commenter 20271 states that startup ends and normal operation of the EGU begins when the EGU has 

achieved minimum stable load and the APCDs have been properly placed in service. For this purpose, 

commenter states that the EPA should use the minimum load for an EGU as defined for the Acid Rain 

Program. Commenter notes that this value is reported to the EPA in each EGU’s monitoring plan.

Commenters 20281, 20282, and 20291 state that EGUs may have difficulty complying with a 30-

operating day average if the end of startup is tied to electricity generation.

Commenter 20291 states that the problem will be compounded by the fact that it is possible for the 

EGUs to startup more than once in a single 30-day averaging period, and the need for startups is not 

predictable.

Commenter 20257 states that the conditions for a fully functioning activated carbon injection (ACI) and 

selective catalytic reduction (SCR) systems will occur well beyond the time that electricity or useful 

thermal energy is initially achieved. Commenter notes that having to incorporate these startup 

concentrations in the 30 day compliance average will make it even more difficult to comply with the 

MACT standards, and this will be compounded if the EGU has multiple startups during the 30 day 

averaging period. Therefore, commenter states, the EPA should define the end of startup as the time 

when emission controls and boiler systems are in stable operation.

Commenters 20277 and 20282 state that the EPA’s definition of “startup” that requires EGUs to begin to 

measure HAP emissions does not match with the EPA’s startup work practice standards, which correctly 

recognize that certain air pollution controls cannot be immediately started without damaging the controls 

or putting plant workers at a safety risk. Commenters state that the EPA fails to recognize that those 

controls will not be fully functional when the EPA defines startup as ending.

Commenters 20269 and 20279 ask that the EPA allow EGUs the choice of using the definitions of 

startup and shutdown provided in the rule or be allowed to create site-specific definitions for startup and 

shutdown. 

Commenter 20288 states that the determination as to when startup ends should be determined on a unitby-unit basis and placed in a unit-specific startup and shutdown plan. 
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Commenters 20270, 20277, 20281, and 20282 suggest that if the EPA does not want to use a case-bycase approach for determining startup, then the EPA should develop different startup definitions based 

on generation type. Commenters recommend startup definitions based on generation type: (1) 

supercritical EGUs; and (2) subcritical EGUs; and (according to Commenters 20270, 20277, and 

20282), (3) FBCs; and (4) IGCC EGUs (as the definitions relate to the gasifier). Commenters provide 

discussion about each of these types of EGUs, with suggestions for startup definitions by EGU type. 

Commenters 20281 and 20282 provide a series of diagrams that show the steps for a supercritical EGU’s 

startup. 

Commenter 20282 notes that these definitions should apply unless the owner/operator demonstrates the 

need for an alternative EGU-specific “startup” because of unique EGU conditions. Commenter states

that in that case, the permitting authority would approve an alternative definition in the EGU’s Title V 

permit.

Commenters 20306 and 20308 support the definitions based on type of generation EGU proposed by 

Commenter 20282 for startup and shutdown.

Commenter 20294 states that although the EPA recognizes the importance of temperature in the startup 

of some controls, the Agency did not address all pollution control equipment. Commenter requests that 

the definition of startup for subcritical EGUs be changed to that recommended by Commenter 20282.

Commenter 20308 recommends that the EPA include startup and shutdown definitions that take into 

consideration distinctions between both the EGU sources and their air pollution control devices

(APCDs), and define startup and shutdown based on individual EGUs and their control devices, for new 

and existing EGUs.

Commenters 20277, 20280, 20282, 20288, 20295, and 20306 suggest that in place of a specific 

definition and work practice standard that applies to all EGUs, the EPA consider imposing a requirement 

that each EGU that is an affected source under the MATS Rule comply with a unit-specific startup 

definition. Commenters state that the definition would be developed by the EGU owner or operator and 

submitted and approved by the permitting authority using the Title V permitting program.

Commenter 20306 recommends that the start-up and shutdown plans be approved separately from the 

Title V permit to allow flexibility for approvable changes as operators learn from repeated startup and 

shutdown events.

Commenter 20288 recommends that start-up or shutdown should be revised in the plan by reaching a 

specified load, emission control equipment reaching full efficiency, or the EGU reaching other specified 

operating conditions. Commenter notes that the startup process could require 12-36 hours or more 

depending upon the situation, and the shutdown periods would generally be shorter, but also vary in 

duration.

Commenter 20282 provides discussion about the differences in startup times between different EGUs.
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Commenters 20281 and 20291 recommend that the EPA apply the Part 63 General Provisions 

definitions of “startup” and “shutdown” to subpart UUUUU. 

Commenter 20281 recommends that as an alternative to the standard definition of startup, an EGU 

operator would be allowed to develop a unit-specific startup plan. Commenter discussed its

recommendations for individual startup plans, including using the HAP and Title V permitting program 

to review plant-specific startup plans. Commenter recommends these changes as an alternative to 

expanded definitions for startup and shutdown periods.

Commenter 20291 recommends that MATS be revised to specify that EGUs have a startup plan 

incorporated into its Part 70 permit. Commenter states that the plan could define when specific pollution 

control equipment will be brought online for that EGU, and could be submitted to the permitting 

authority. Commenter states that the plan could also specify that best operational practices will be 

followed to startup the EGU as quickly and safely as possible to minimize emissions. 

Commenter 20279 states that for EGUs that select the site-specific option, SS plans would allow owners 

and operators to determine when startup and shutdown begins and ends based on parameters that are 

easily monitored at that EGU. Commenter states that these parameters could be based on requirements 

in other rules to which EGUs are already subject. Commenter notes that as an example, EGUs subject to 

the Acid Rain Program are already required to define the EGU’s ranges of operation and normal load

(see 40 CFR Part 75, Appendix A, section 6.5.2.1). Commenter states that startup and shutdown for such 

EGUs could easily be based on these ranges of operation. Commenter notes that other EGUs may decide 

that startup will end at the time the EGU is synchronized with the utility electric distribution system and 

that shutdown will begin when the EGU ceases to be synchronized with the utility electric distribution 

system. Commenter states that this is a more precise delineation of the boundaries of startup and 

shutdown for EGUs that produce electricity during startup prior to connecting with the grid.

Commenter 20279 states that allowing EGUs the option to develop SS plans would avoid potential 

conflicts between the MATS and other applicable requirements, would regulate SS more efficiently than 

applying multiple, overlapping SS requirements, and would reduce unnecessary administrative burdens 

on regulated sources. Commenter urged the EPA to allow EGUs to elect to either follow the proposed 

definitions of startup and shutdown, or to follow an individualized SS plan.

Commenter 20281 provides examples of emissions variation during extended startup conditions.

Commenter 20282 provides attachments showing mercury (Hg) emissions spikes prior to full 

engagement of the SCR, and other examples of commenter’s point that control systems have a transition 

period before full emission control effectiveness. 

Commenter 20273 states that based on the start-up profile for its facility, the new definition of start-up 

will likely shorten the period of time defined as start-up by one or 2 hours. Commenter states that its

facility start-up profile provides that petroleum coke is not burned until sometime after main steam flow 

is established. Commenter states that therefore, at the end of the EPA prescribed start-up period, the 

EGUs will be burning primarily natural gas or propane. Commenter states that because the reconsidered 

MATS are based on 30-operating day rolling averages, the shorter start-up period may result in higher 

initial sulfur dioxide (SO2) emissions counted in the first averaging period after an EGU start. 
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Commenter states that this is due to the higher SO2 emissions as the circulating fluidized bed (CFB)

boilers are transitioned to petroleum coke with stabilization of limestone injection in the CFB bed, and 

the circulating dry scrubber – flue gas desulfurization (CDS-FGD) system is brought into service. 

Commenter states, thus, SO2 emissions could spike as petroleum coke is fired and could result in an 

exceedance of the tight SO2 MATS. Commenter states that at this time, there is insufficient information 

to understand the impact of a shorter start-up period on SO2 MATS compliance. Commenter notes that 

in a D.C. Circuit filing made on January 6, 2012, Case No. 12-1100, Document No. 1413644, the EPA 

has acknowledged that it is continuing its reconsideration of start-up in the MATS rule and, hopefully, 

will appropriately address the issue described above.

Commenter 20251 suggests that the definition of startup should cover the time where emissions may be 

higher due to the startup event. Commenter provides the following revised language for the definition of 

startup given in 40 CFR 63.10042 of the MATS rule: 

Startup means the period in which operation of an EGU is initiated for any purpose. 

Startup begins with either the first-ever firing of fuel in an EGU for the purpose of 

producing electricity or useful thermal energy (such as heat or steam) for industrial, 

commercial, heating, or cooling purposes or the firing of fuel in an EGU for any purpose 

after a shutdown event. Startup ends when all pollution control equipment that is 

necessary to comply with the applicable emission limits under this Subpart are engaged. 

Needed pollution control equipment shall be engaged as expeditiously as possible, 

considering safety, good engineering practices and manufacturers’ recommendations. the 

EGU generates electricity that is sold or used for any other purpose (including on site 

use), or the EGU makes useful thermal energy (such as heat or steam) for industrial, 

commercial, heating, or cooling purposes (16 U.S.C. 796(18)(A) and 18 CFR 

292.202(c)), whichever is earlier.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

1.1.1.1 25 percent plus 3 hours, or generation plus 6 hours

Comment 2: Commenters 20384 and 20389 support defining the end of startup as occurring at 25 

percent of nameplate capacity (or greater) plus 3 hours, or the start of electricity generation plus 6 hours, 

whichever comes first. 

Commenter 20387 supports defining the end of startup as engaging all APCD equipment (except SCR) 

at 25 percent of nameplate capacity (or greater) plus 3 hours, or the start of electricity generation plus 6 

hours, whichever comes first. 

Commenter 20390 supports a default nominal electrical production rate of 25 percent of rated capacity 

for startup and shutdown or until the EGU achieves steady state of 10 percent oxygen (O2), whichever 

comes first.

Commenter 20418 states that the definition applied to the end of startup should be based solely on 

achieving 25 percent nameplate capacity plus a certain number of hours. Commenter states that the 
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number of hours should be more than 3 to ensure facilities can adequately comply with the MATS 

requirements.

1.1.1.2 25 percent plus 4 hours, or generation plus 12 hours

Comment 3: Commenter 20391 states that the EPA should redefine the end of startup to adequately 

reflect the length of time needed to set an EGU into operation. Commenter states that the EPA’s choice 

of defining “end of startup” as the initial production of electricity is still problematic because it does not 

fully consider whether emission controls are still being “set into operation,” and thus whether an EGU 

has a steady-state emissions profile. Commenter states that ending startup when electricity is first 

produced does not account for the time needed to set the boiler and its associated air pollution control 

equipment into operation and fails to recognize that electricity production and startup are not by 

definition distinct modes, but instead typically overlap. Commenter states electricity generation 

normally begins when the boiler’s steam load is less than 10 percent. Commenter states that at this point 

in the startup process, startup fuel is still being burned, either alone or in combination with coal, and 

major components of the EGU including pollution control equipment are neither online nor fully 

functioning. Commenter states that as a result, spikes in HAP emissions can occur after the defined end 

of “startup” as currently proposed. Commenter states that EGUs may have difficulty complying with a 

30-day operating day average if the end of startup is tied to initial electricity generation. Commenter 

states that this problem will be compounded by the fact that it is not uncommon for EGUs to start up 

more than once in a single 30-day averaging period because EGU startups are controlled by a third party 

regulator (e.g., the regional transmission authority). Commenter states that the demand for starts is 

driven by weather, customer actions and the reliability of other EGU’s in a regional generation system, 

none of which are always predictable.

Commenter 20391 states that the EPA should modify how it defines “startup” to provide additional time 

to complete startup operations so as to allow all emission control devices to reach full operational 

effectiveness before “startup” ends. Commenter states that the definition should reflect the length of 

time actually needed to set an EGU into operation. Commenter states that for these reasons, it generally 

supports, as an option, the concept of setting a presumptive (or default) definition for the end of startup 

that is tied to gross load levels (electricity generation as a percentage of nameplate capacity) and the 

time needed for control equipment to reach operational effectiveness. Commenter states that this concept 

was recommended by Commenter 20282 in its comments on the initial reconsideration proposal, 

suggesting that the end of startup for EGUs be defined as occurring at least 4 hours after 25 percent of 

nameplate capacity is first achieved or 12 hours after first electricity generation, whichever occurs first, 

for subcritical coal EGUs and fluidized bed EGUs (“the 4/12 test”).

Commenter 20391 states that the EPA appears to have endorsed this approach, and has solicited 

comment on defining the end of startup as 3 hours after 25 percent load is first achieved or 6 hours after 

first electricity generation, whichever occurs first (a “3/6” test), based on an analysis discussed in the 

technical support document (Startup TSD) “Assessment of startup period at coal-fired electric 

generating units” (EPA-HQ-OAR-2009-0234-20378). Commenter states that the EPA’s definition 

proposed in the reopening notice is a substantial improvement over the definition based solely on first 

electricity generation that was proposed in the initial reconsideration notice. Commenter states however, 

the analysis supporting the “3/6 test” focuses on “normal” or average startups and does not capture the 

inherent variability in how any given EGU starts up Commenter states that for example, an analysis 
9

performed in support of Commenter 20428’s “4/12 test” suggests that startups at EGUs sharing a 

common stack extend well beyond 6 hours after first electricity generation. Commenter states that in 

addition, the EPA’s analysis is focused only on SO2 and nitrogen oxides (NOx) emissions and does not 

include Hg emissions or particulate matter (PM) emissions (that are used as a surrogate for non-mercury 

metals in the Utility MATS rule), whereas its analysis included Hg and PM. Commenter states that 

accordingly, it believes that lengthening the time periods to the “4/12 test” suggested by Commenter 

20428 would better serve as a presumptive definition for end of startup and better capture the variability 

of startups across the universe of EGUs subject to the MATS rule.

Comment 4: Commenter 20400 states that the MATS definition of startup excludes operations that are 

part of the startup process. Commenter states that although the generation of electricity is a very bright 

line which is easy to define, many startup activities continue well past this point. Commenter states that 

emissions are also different because the control equipment has not reached the operating conditions that 

allow it to function at full effectiveness. Commenter states that as an example, certain types of FGD 

systems will not have reached proper chemistry conditions which will influence SO2 and Hg emissions. 

Commenter states that fluidized bed EGUs that inject limestone must reach a minimum temperature of 

approximately 1,500 °F for the limestone to calcine, and thus become effective at reducing acid gases. 

Commenter states that in the current rule making, the EPA has recognized comments from various 

parties, including the commenter that show that startup activities continue well past the time that 

electricity is first generated. Commenter states that as a result, the EPA has the justification to modify 

and expand the definition of a startup from its current form.

Commenter 20400 states that the EPA designed the Utility MACT information collection request (ICR)

so that no data was collected during these periods and operators generally have had no reason to collect 

such data either. Commenter states that startup and shutdown periods have highly variable operating 

conditions and consequently, reference test methods cannot be utilized because the sources do not 

operate in a steady state as required by the methods. Commenter states that in addition, the EPA lacked 

sufficient information from continuous emission monitoring systems (CEMS) because the use of PM, 

Hg, and hydrogen chloride (HCl) CEMS were not in wide spread use and insufficient data was available 

to develop standards during these periods. Commenter states that without this information, the EPA has 

no way of knowing if emissions standards based on 30-day rolling averages are appropriate to address 

less predictable emissions during startups and shutdowns.

Although Commenter 20400 agrees that the EPA’s selection of work practice standards during startup 

and shutdown periods is appropriate, it disagrees with the EPA’s determination that a startup ends when 

electricity is first generated. Commenter states that rather, that there are additional important steps that 

occur after the generation of electricity begins and that the EPA should acknowledge these steps by 

expanding the startup definition. Commenter is concerned that if the EPA does not expand the 

definition, then EGUs, including the well-controlled EGUs used to set the emission standards, will have 

difficulty complying with the emissions standards, specifically Hg, because of the higher emission rates 

occurring during these periods. Commenter states that although startups ideally occur infrequently, it is 

highly certain that all sources will at some times experience times with two or more startups during a 

single 30-day averaging period. Commenter believes this hinders a source’s ability to average down the 

potentially higher startup emissions and greatly increases the potential for non-compliance.
10

Commenter 20400 does not have the same issue with regards to the EPA’s shutdown definition and it 

believes EGUs will spend little time in that shutdown period, and, therefore, there is not a problem of 

the same severity. Commenter notes that when an EGU trips offline suddenly, the combustion of fuel 

stops in less than a minute. Commenter states that during a controlled shutdown, load is gradually 

reduced to a lower level, and then the EGU is intentionally tripped and fuel flow also stops in less than a 

minute. Commenter notes that IGCC EGUs have a different shutdown process.

Commenter 20400 states that it is important that the regulation account for the full period of startup 

activities, not just the time until the generator first produces electricity. Commenter states that by nature, 

startup is a period of suboptimal operation where the operators are engaging numerous systems and 

processes to bring the EGU to normal operation. Commenter states that the sub-optimal conditions not 

only affect the performance of pollution control systems (and the mass of emissions leaving the stack) 

but also affect the generation efficiency. Commenter states that because each of the MATS emissions 

standards include an output-based standard (required for new EGUs and optional for existing EGUs), 

including periods where electricity generation has begun but the EGU has not yet achieved normal, 

stable operation is not appropriate because the output-based emissions rate during this period will not be 

representative of the emissions rate during normal EGU operation.

Commenter 20400 continues to recommend that for a supercritical EGU (one that generates steam that is 

in excess of 3,206.2 pounds per square inch, atmospheric (psia) and 705.40 °F), startup should end 6 

hours after the transition from subcritical to supercritical mode concludes. Commenter states that for 

subcritical EGUs ’(from commenter’s perspective, a subcritical EGU is one that does not operate with 

supercritical steam and includes conventional drum EGUs, EGUs that are stoker fired, or EGUs utilizing 

FBC), the startup period should end 4 hours after the EGU reaches 25 percent of full load capacity. 

Comment 5: Commenter 20400 disagrees with the EPA’s analysis and conclusions concerning the 

length of an EGU startup. Commenter states that in the current rulemaking notice the EPA states “We 

believe these results could support defining the end of startup at coal-fired EGUs as occurring at 25 

percent of nameplate capacity plus 3 hours or the start of electricity generation plus 6 hours, whichever 

comes first, and we are soliciting comment on the analysis.” Commenter states that the EPA’s Startup 

TSD states that “all types of EGUs in this study can reach 25 percent of nameplate capacity in 3 hours or 

less after the start of generation. Commenter states that in its Startup TSD, the EPA also quotes the 

Babcock and Wilcox Company (B&W), a major boiler equipment manufacturer, to conclude that “larger 

coal-fired EGUs may need 4 to six hours for startup.” Commenter disagrees with these three statements. 

Beginning with the quotation that the EPA took from EPA-HQ-OAR-2009-0234-20381, commenter

finds that the EPA has taken a short passage and has read it completely out of context. Commenter 

provides the complete paragraph is as follows:

Cold start and low load operation

Cold boiler startup requires firing at low heat input for long periods of time to avoid expansion 

difficulties and possible overheat of the superheaters or reheaters. Low pressure (200 psig (1.38 

MPa gauge)) boilers without superheaters may need only about an hour of low load operation. 

Larger high pressure units however, may need four to six hours for startup. During startup, 

combustion efficiency is typically poor, especially with residual oils, due largely to low furnace 

and combustion air temperatures.
11

Commenter 20400 states that as a first matter, this quotation comes from a chapter entitled “Oil and Gas 

Utilization.” Commenter states that although the EPA may be relying on this chapter to justify a startup 

period for oil-fired EGUs, the chapter is clearly not intended to refer to an oil-fired EGU. Commenter 

states that even to the extent that it could apply to any EGU, according to the EPA, B&W states that an 

EGU startup only requires 4 to 6 hours. Commenter states that however as seen in the actual paragraph, 

B&W is not referring to an entire EGU and all its components; rather it is referring only to the boiler 

portion of an EGU. Commenter states that the boiler by itself must be started before it is capable of 

delivering steam to the turbine so that the first electricity can be generated. Commenter states that the 

passage that the EPA quotes is very general in nature and applies across the wide variety of products that 

B&W provides for many industries. Commenter notes that the boilers supplied for EGUs are generally 

the largest made and are very specialized. Commenter states that as a result it is not appropriate for the 

EPA to use such a general comment to characterize performance in a very specialized application.

Commenter 20395 states that the EPA misquotes the B&W Steam book by citing that large coal-fired 

EGUs “may need four to six hours for startup.” Commenter notes that, in fact, this statement by B&W is 

not in the section for coal-fired EGUs at all, rather in the oil and gas chapter and that even if this were 

true for the boiler, the EPA must consider the startup of the system, not just the boiler. Commenter 

maintains that actual EGU startup for purposes of emissions reduction involves the “setting in 

operation” of the boiler and its APCDs.

Commenter 20400 states that a major flaw in the EPA’s Startup TSD analysis is that it determines an 

average performance and attempts to characterize that all EGUs are capable of attaining that average 

performance. Commenter states that this analysis fails for two reasons. Commenter states that first it 

assumes that all EGUs are constructed similarly and have pretty much the same startup process. 

Commenter states that second, it fails to recognize that even at the same EGU, startup times will vary 

and that there are differences between the length required for hot, warm and cold startups. Commenter 

also states that in its analysis, the EPA recognizes that the hours of fossil fuel combustion before 

generation are different for different types of startup. Commenter states that however it fails to recognize 

that the length of time after electricity is first generated until the EGU reaches 25 percent load will vary.

Commenter 20400 states that although there are many causes, an easily explained scenario concerns the 

steam turbine. Commenter states that the firing of fuel in a boiler allows it to be warmed well before 

electricity is first generated. Commenter states that however full warming of a steam turbine can occur 

only after steam is admitted and the generator is connected to the grid. Commenter states that once high 

temperature steam is admitted to the turbine the rotating elements and the shell begin to heat up and to 

expand. Commenter states that because the components expand at different rates, the rate of heating 

must be controlled and limited to prevent internal damage. Commenter states that the amount of turbine 

heating required is different for cold, warm and hot starts. Commenter states that this can lead to 

extended startup periods.

Commenter 20400 states that in addition to the steam turbine example, EGU operators experience many 

different circumstances that protract a startup period. Commenter states that an EGU is an extremely 

complicated assembly comprised of dozens of sub systems and thousands of individual components. 

Commenter states that all components must work together, and any one component not operating 

properly may delay the startup process. Commenter states that these delays are caused by physical 
12

constraints (i.e., the EGU just cannot physically produce more electricity), are necessary to prevent 

damage to equipment (such as insuring proper water and steam chemistry, or thermal requirements) or 

for personnel safety. Commenter states that many of these constraints regularly occur in the period from 

when an EGU first generates electricity until after it reaches 25 percent of its full load capability. 

Commenter provides six specific examples as follows:

• For removing SO2 and Hg, some EGUs have multiple FGD scrubber modules. 

Commenter has one facility that has six scrubber modules. When starting that EGU, only 

three modules may be in service. As power increases, additional modules are placed into 

service. Each module goes through its own startup process and requires time before it 

reaches the right chemical equilibrium that produces the full effectiveness.

• When an EGU is not producing electricity, it must be supplied with electric power from 

the outside grid. Once the EGU generates sufficient power (typically less than 25 percent 

load) the power supply for station equipment is transferred to the output of the generator. 

This involves switching very high voltage transformers and must be done under 

controlled conditions. Failure to execute this step properly will result in a failed startup.

• During a startup, it is common to have hold points for boiler water chemistry. These 

holds limit EGU output until the water reaches minimum purity levels. Failure to observe

these holds will cause damage to boiler tubing and turbine components.

• The rate of a startup often depends upon the type of shutdown. In many cases an EGU 

will rapidly trip off line unexpectedly. This can leave pulverizers and burner lines full of 

unburnt fuel as well as other difficulties. Regardless of whether it is a hot, warm or cold 

restart, the type of shutdown will impact the length of the next startup.

• As power increases, additional coal pulverizers are placed into service. Oil fired igniters

are used to light off the coal flow during a pulverizer startup. Delays are common due to 

lighter operation, and/or problems with the pulverizer itself. Failure to properly start a 

pulverizer can result in fire or explosion placing equipment and personnel at severe risk.

• During a startup, bottom ash and flyash handing systems must be placed into service. It 

is common to have pluggage in these systems during a startup, particularly in flyash 

hoppers. If ash handling systems do not function properly, then the amount of load must 

be limited until they are properly in service.

Commenter 20400 states that although this list cites only a limited number of examples, all EGUs will 

experience extended startups, which is something that EGU operators cannot prevent. Commenter states

that the EPA’s analysis characterized that EGUs can startup and achieve 25 percent load in 

approximately 3 hours. Commenter states that however the EPA arrived at this conclusion based on 

average performance. Commenter states that this essentially means that half of the EGUs can achieve 

these times and half cannot. Commenter states that this matters because EGUs must be in compliance 

with the MATS standards at all times. Commenter states that emissions control equipment only reaches 

its full effectiveness once an EGU can attain the proper load and the control equipment reaches the 

proper condition. Commenter states that a review of the EPA’s own data shows that longer startups are 
13

very common. Commenter states that using the EPA’s spreadsheet analysis (EPA-HQ-OAR-2009-0234-

20378), Commenter identified 6,522 successful startups where the average time to reach 25 percent load 

was about 2.8 hours. Commenter states that the standard deviation of this data was 2.43 hours which 

indicates a large amount of variability. Commenter states that of these successful startups, 1,520 

extended to 4 or more hours, and 408 of those startups required 7 or more hours to achieve 25 percent 

load. Commenter states that this supports its recommended startup definition of reaching 25 percent of 

load plus 4 hours for subcritical EGUs and completing transition to super critical mode plus 6 hours for 

super critical EGUs. From commenter’s experience, these time periods are sufficient to allow operators 

to work through the many challenges it faces in operating EGUs.

Comment 6: Commenter 20400 states that startup for subcritical EGUs should conclude at least 4 hours 

after an EGU reaches 25 percent capacity. Commenter states that for subcritical, or conventional drum 

EGUs, it is harder to identify the same bright line point in the startup process that is tied to an 

operational change because there are many plant equipment configurations and many different ways in 

which subcritical EGUs startup. Commenter states that some subcritical EGUs generate their first 

electricity while still combusting only their startup fuel whereas others do not. Commenter states that 

some EGUs use steam driven boiler feed pumps for normal operation, but use a lower capacity electric 

feed pump for startup. Commenter states that startup activities include the closing of boiler and turbine 

startup vents and drains, but only after sufficient steam temperature and pressure are reached. 

Commenter states that as a final example, many plant systems such as the coal pulverizers are operated 

in manual mode until the EGU reaches a minimum power level. Commenter states that subcritical EGUs

share many of the same operational concerns during startup that supercritical EGUs face, which 

contributes to higher emissions immediately after the first generation of electricity. Commenter states

that the difference is that they do not face the added delays caused by the transition to supercritical mode 

of operation.

Commenter 20400 states that the EPA has suggested that one alternative is to extend the use of cleaner 

fuels such as fuel oil or natural gas for longer periods of time during startup to replace fuels such as coal. 

Commenter states that the systems that supply these fuels to the boiler, however, are generally too small 

to replace coal. Commenter states that as an example, one type of its coal pulverizers has seven or eight 

individual burner lines, and it is used for both subcritical and supercritical EGUs. Commenter states that 

each of the burner lines is paired with an oil gun that is used to light the coal fire and to stabilize the coal 

flame when the pulverizer is operated at lower capacity. Commenter states that the heat input from coal 

for this pulverizer is about 1,200 million British thermal units per hour (MMBtu/h) per hour, whereas

the oil guns are only capable of delivering 17.5 MMBtu/h. Commenter states that clearly the oil guns do 

not have the capacity to deliver the same amount of heat provided by the coal pulverizers. Commenter 

states that even if the oil guns were radically increased in total capacity, the rest of the system including 

tanks, pumps, piping, controls, etc. would all have to be increased to match. Commenter states that as a 

result substituting cleaner fuels in place of coal can have only a limited effect or would require extensive 

modification just to accommodate more use of these fuels during startup periods.

Commenter 20400 states that considering all these factors, it recommends that the end of “startup” for 

subcritical (i.e., conventional drum) coal-fired EGUs should be defined as 4 hours after 25 percent load 

is first reached, or 12 hours after first electricity generation, whichever occurs first. Commenter states

that the 4-hour timeframe would provide for a transition period while a facility removes the startup fuel 

and transitions to complete primary fuel firing, shuts down a dedicated startup system (if applicable), 
14

and ensures that all emission control equipment can come online safely and within intended design 

capabilities to achieve full effectiveness. Commenter states that the 12-hour maximum would cover 

situations where the startup sequence is delayed for unexpected reasons, but still provides assurance that 

an EGU will not idle at low load. Commenter states that the 6-hour maximum the EPA suggested in its 

analysis is not sufficient to address events that might delay the completion of startup. Commenter states

that although there are different plant configurations and procedures, many subcritical EGUs will also 

have higher emissions during startup albeit for different reasons. Based on commenter’s experience, the 

combination of 25 percent load plus four additional hours will reasonably and broadly address the 

situation for subcritical EGUs.

Comment 7: Commenter 20400 states that expanding the definition of startup is justified because EGU 

emissions are different during this period. Commenter states that as an example of how emissions are 

different during startup conditions, it included two graphs of SO2 and EGU load data for its Zimmer 

Generating Station during two separate startup events. Commenter states that for SO2, they illustrate a 

characteristic peak in emissions while the proper FGD chemistry is established. Commenter states that 

peak removal was not achieved until a couple days after the EGU reached full load. Commenter states

that it should also be noted that during the first event, the EGU was started, achieved a relatively high 

load, but then had to shut down and then immediately went into a second start-up. Commenter notes this 

particular startup event lasted over 3 days.

Commenter 20400 states that this particular EGU is one of a number of EGUs that utilize magnesium 

enhanced lime as a reagent. Commenter states that it is well established that these types of FGD systems 

require 24 - 36 hours after electricity generation begins before they achieve their full SO2 reduction 

potential. Commenter states that it takes this amount of time to achieve the proper chemistry conditions. 

Commenter states that higher levels of excess air at lower loads during a startup retard this process. 

Commenter states that in addition to enabling the best SO2 removal, proper scrubber chemistry is 

essential to achieving optimal Hg removal in the FGD system.

Commenter 20400 notes that in its comments, Commenter 20428 has conducted an analysis of startup 

emissions from a number of EGUs. Commenter has reviewed these results and supports Commenter 

20428’s analysis and conclusions.

Commenter 20395 states that although the EPA’s latest suggested revisions represent improvements 

over the final rule and the proposed reconsideration, it falls short of the “setting in operation” of the 

source, including the emission control devices. Commenter indicates that the General Provisions 

governing all MACT regulations define startup as “the setting in operation of an affected source or 

portion of an affected source for any purpose.” Commenter alleges that as the EPA has suggested 

defining it, startup would always end within 6 hours after the first electricity production. Commenter 

maintains that 6 hours after electricity production, however, is not enough time to ensure that that the 

boiler and associated APCD have reached a safe or stable normal operating condition and that emissions 

are being effectively controlled for normal operation.

Comment 8: Commenters 20414 and 20430 do not believe that “defining the end of startup at coal-fired 

EGUs as occurring at 25 percent of nameplate capacity plus 3 hours or the start of electricity generation 

plus 6 hours, whichever comes first” provides adequate flexibility for coal-fired EGUs to ensure safe, 
15

efficient, and compliant operation. Commenters recommend establishing the end of startup at 25 percent 

of nameplate capacity plus 4 hours.

Commenters 20414 and 20430 state that roughly half of the ’nation’s coal-fired EGUs will take longer 

than the average EGU to bring a control technology online in the case of median data, exactly half will 

take longer. Commenters say by using average, and at times median, power plant data, the EPA is 

establishing a startup standard that would inappropriately classify half of the country’s EGUs as 

completing startup when, for many of those EGUs, startup would still be continuing. Commenter 20414 

states that this means that, under the EPA’s definition of startup, roughly half of the subcritical and 

supercritical EGUs (whether using wet or dry FGD technologies) would not have a declining SO2

emissions rate (i.e., operational FGDs) 3 hours after reaching 25 percent load. Commenter 20414 states

that it also means that half of the subcritical and supercritical EGUs with SCRs will not have operational 

SCRs within 6 hours after the start of generation and that half of the CFB EGUs will not be 

demonstrating SO2 emission rate reductions within 4 to 6 hours after the beginning of generation.

Commenter 20430 states that the EPAs Startup TSD for NOx indicates EGUs that meet the criteria of 

having APCDs in service would have declining NOx rates at the end of the proposed startup time but 

does not indicate they will be in compliance with their air permit. Commenter maintains that the end of 

startup should be at the point where the EGU is capable of meeting compliance with its air permit.

Commenters 20414 and 20430 state the EPA’s Startup TSD is also based on the control technologies 

currently in operation at existing EGUs. Commenters say as the MATS rule is implemented, and the 

EPA’ s numerous other air regulations are finalized, many of the Nation’s power plants will be adding 

new control technologies and control technologies in combinations that have never been used at those 

respective power plants. Commenters say there will inherently be a learning curve and potential 

unforeseen problems that would require additional time to bring a plant and control technologies online.

Comment 9: Commenter 20425 states that the EPA’s proposed definition of “startup” does not take into 

account the uniqueness of different EGUs – even identically designed EGUs have different operating 

and startup characteristics. Commenter notes that supercritical and once-through subcritical EGUs rely 

on a start-up/bypass system to bring the EGU up to stable, safe, and reliable operation; these 

startup/bypass systems are typically designed for 25 percent of nameplate capacity. Commenter states, 

however, many once-though design EGUs do not obtain stable, safe, and reliable operation until they are 

fully isolated from the startup/bypass system and are sufficiently above the transition point from the 

startup/bypass system to once through operation which is approximately 30 percent of nameplate 

capacity. Commenter alleges, therefore, that the start-up period should be tied to 30 percent and not 25 

percent for once-through supercritical and once-through subcritical EGUs.

Commenter 20425 states EGU startups involve managing and coordinating the startup and operation of a 

number of complex systems which must be done in a safe, environmentally compliant and efficient 

manner. Commenter notes that these systems are typically operating outside of their normal design 

conditions during startup which makes the control of these systems difficult and susceptible to issues 

during startup that can lead to unexpected delays in bringing the EGU to a safe, environmentally 

compliant, stable, and reliable operation. Commenter states that if the startup definition is based on EGU

type then the following criteria should be applied:
16

Supercritical and Subcritical once through EGUs – whichever comes first: 4 hours after 

achieving 30 percent nameplate capacity, or 12 hours after achieving electrical 

generation.

Subcritical Drum EGUs – whichever comes first: 4 hours after achieving 25 percent 

nameplate capacity, or 12 hours after achieving electrical generation.

FBC EGUs – whichever comes first: 3 hours after the bed temperature reaches 1500 °F, 

or 12 hours after achieving electrical generation. As an alternative – whichever comes 

first: 4 hours after achieving 25 percent nameplate capacity, or 12 hours after achieving 

electrical generation.

Commenter 20426 recommends and supports the startup definition proposed by Commenters 20396, 

20397, and 20428. Commenter states that, as an example, Commenter 20428 suggests that the simplest 

way to define the end of “startup” for subcritical (i.e., conventional drum) coal-fired EGUs like the 11 

EGUs Commenter 20426 operates is 4 hours after 25 percent load is first reached, or 12 hours after first 

electricity generation, whichever occurs first.

Commenter 20426 states that the EPA’s proposed definitions do not consider material differences in 

either the source or the associated air pollution control equipment; a one-size-fits-all definition must 

expressly allow consideration of the air pollution control processes used in determining the emission 

limitations that depend on temperature, flow, and/or chemical equilibrium to be effective. Commenter 

notes that, for safety and operational reasons, when an EGU at one of its facilities is being returned to 

service, it goes through a startup sequence that includes introducing fire in the boiler with oil lighters 

and then introducing coal. Commenter states that the coal is introduced one mill at a time until a stable 

flame is achieved and the oil lighters can be taken out of service; each EGU has seven mills and at least 

two or three need to be in service to get a stable flame. Commenter indicates that during this startup 

period, combustion gases are not routed through the SCRs, but the gas is routed through all other 

pollution control equipment, including the ESPs and the scrubber – the SCRs are bypassed during 

startup for safety and operational reasons as oil carryover during a startup can contaminate the catalyst 

in the SCR rendering it useless and it can even cause a fire; thus, the gases bypass the SCR during 

startup until a stable flame is achieved and the oil lighters are taken out of service. Commenter states 

that once this step is achieved, the gases are routed through the SCR, it is heated up and, once operating 

temperatures are achieved, then the ammonia injection is initiated and the SCR becomes operational for 

NOx control.

Commenter 20429 notes that should the EPA choose to implement a generic approach, it supports 

Commenter 20428’s suggestion that startup should end 4 hours after 25 percent load is reached or 12 

hours after first electricity generation, whichever occurs first. Commenter states that although this 

additional time would accommodate more of the startup variability for different EGU designs and from 

EGU to EGU and as conditions vary from startup to startup, the third prong of this approach 

(“whichever occurs first”) ensures that an EGU will not be idled at low load.

Comment 10: Commenter 20417 states that in the June 25, 2013, notice reopening the public comment 

period (78 FR 38001), the EPA suggests that its data analysis supports the possibility of defining the end 

of startup at coal-fired EGU as occurring at 25 percent of nameplate capacity plus 3 hours, or the start of 
17

electricity generation plus 6 hours, whichever comes first. Commenter states that, as stated in the 

proposal, commenters suggest allowing more time for startup by defining the end of startup as occurring 

at 25 percent of nameplate capacity plus 4 hours or the start of electricity generation plus 12 hours, 

whichever comes first. Commenter appreciates the EPA’s consideration of adding some flexibility to the 

startup definition. Commenter states that both options do allow for some extra time to bring emission 

controls on-line during startup activities.

Commenter 20417 notes, however, taking a “one-size-fits-all” approach to defining how all EGUs are to 

complete their startup activities will likely force many plants to choose between compliance with the 

proposed definition of startup (even with the added time noted above) or disregarding manufacturer 

recommendations, disregarding existing plant procedures that are based on good engineering practices, 

incurring damage to plant emission control equipment, or creating potentially unsafe work 

environments, in order to comply with the proposed definition. Commenter states that many of the 

emission controls (e.g., ESPs and baghouses) that will be used to ensure compliance with the MATS 

Rule are dependent on temperature for determining the safe and appropriate time to begin their 

operation. Commenter states that not every EGU at every plant will be able to achieve the appropriate 

temperatures for proper operation of emission control equipment even within the additional time 

proposed by the EPA in the proposal.

Commenter 20417 states that, in the EPA’s November 30, 2012, proposal (77 FR 71323), the EPA

recognized that some control equipment takes longer to place in operation than others. Commenter states

that, more specifically, in the November 30, 2012, notice, the EPA proposed to exclude additional 

emission controls from the requirement to be in service when certain fuels were first fired because the 

EPA recognized there are certain constraints to their operation. Commenter states that, the final MATS 

Rule currently states that those exempted controls must be started as “expeditiously as possible.”

Commenter states that, in the November 30, 2012, notice, the EPA states that the exempted control 

systems should “start as soon as technically feasible after the appropriate temperature has been reached.”

Commenter believes this is the better approach than defining startup in the way that the EPA has stated 

in the June 25, 2013, notice as it recognizes the unique operating constraints of emission control 

equipment.

Commenter 20417, in its comments on the November 30, 2012, proposal (EPA-HQ-OAR-2011-0044-

5803, p. 5), supports the EPA’s proposed expansion of the “exempted” emission controls and asks that 

the EPA consider adding additional emission control equipment to the discussion due to similar 

operating constraints. Commenter states that, considering the multitude of issues that are involved in 

safely bringing emission control equipment online, and that every EGU is different in their operating 

needs, the best approach may be to provide even greater flexibility in the definition of startup similar to 

the approach the EPA has taken when additional controls need to be in service when certain fuels are 

first fired.

Comment 11: Commenter 5840 notes that the time required for startup at each EGU is dependent upon 

a number of factors including, but not limited to, the EGU type, length of time the EGU has been down, 

the amount of process water cleanup that is required, and the specific work performed during the EGU

down time. Commenter states that each step of the startup process is driven by equipment temperature 

constraints such that boiler steel, fans, turbine-generator equipment, and other rotating parts are heated 

at predetermined rates to allow for expansion and avoid potential damage from metal fatigue. 
18

Commenter maintains that a startup following outages that include significant maintenance on large 

components of the boiler (process tubing, piping, headers, ductwork, etc., steam turbine, generator, or 

other support equipment) can take significantly more time than if the EGU had simply experienced a trip 

and was quickly restarted. Commenter alleges that the additional time is required not just for 

predetermined heating rates, but also for check and reset of control points, instrument calibration, 

balancing of rotating equipment, assuming that boiler water quality requirements are met and other work 

necessary to return the EGU to service and that local weather conditions can also be a factor in the 

length of time it takes to heat EGU components and to retain that heat as startup steps proceed.

Commenter 5840 suggests modification to the EPA’s proposed definition of the end of startup. 

Commenter proposes that the end of startup be defined as reaching 25 percent of nameplate generation 

capacity plus 4 hours. Commenter states that the whichever-comes-first approach does account for some 

of the variability among EGU startup profiles and EGU equipment, but results in a complicated data 

management challenge and additional burden for emission reporting personnel. Commenter maintains 

that determining which threshold was reached first will require additional data review and 

documentation at all facilities and that this burden is ignored in the development of the proposed rule. If 

the EPA retains a generation plus time definition for the end of startup, Commenter recommends 

generation plus 12 hours be used. Commenter states that the additional time would help avoid 

shutdowns that could occur due to problems encountered in setup. Commenter believes that in many 

cases there is little time difference in reality in the EPA’s proposed 25 percent capacity plus 3 hours and 

generation plus 6 hours.

Commenter 5840 maintains that operators may have to choose to bring an EGU down rather than 

continuing a difficult startup to avoid risking failure to meet numerical limits at the point corresponding 

to the EPA’s suggested end of startup definition which would have the undesirable effect of actually 

increasing emissions by increasing the number of startups and shutdowns. Given the variability in EGU 

startup times and the potential for reducing the number of startups, commenter believes that these minor 

adjustments in the EPA’s recommended definition of the end of startup will result in lower overall 

emissions, and more efficient and effective engagement of APCD. Commenter believes that the EPA’s 

own assessment of a startup period at coal-fired EGUs shows that there are supercritical EGUs that do 

not reach 10 percent of nameplate generating capacity until 6 hours after generation of electricity begins.

Commenter 20428 states that if the EPA insists on an across-the-board definition of startup, then the 

EPA must lengthen the time periods; the EPA’s suggested 3/6 definition still does not provide adequate 

time for control equipment to be “set in operation” safely and reliably when startup is defined as ending. 

Commenters 20395, 20397, 20413, 20414, 20428, and 20430 state the EPA should define startup as 

ending: 4 hours after 25 percent nameplate capacity is reached, or 12 hours after initial electricity 

generation, whichever occurs first. Commenter 20395 further notes that this default definition would 

apply unless the permitting authority approved an alternative due to unique EGU conditions. Commenter 

20428 further clarifies the three components of its suggested startup definition: 4 hours after 25 percent 

load is first reached; 12 hours after first electricity generation; and whichever comes first. Commenter 

20428 notes that it intentionally designed its three-part startup test to provide necessary compliance 

flexibility to EGU owners and operators during the inherently unpredictable and variable period of 

startup while providing assurance to the EPA that owners and operators would not “game the system”

and stay in “startup.” Commenters 20414 and 20430 state that the 4/12 startup definition would ensure 
19

that the definition of the end of startup is derived in a mathematically supportable fashion and would 

provide certainty without undue complexity.

Commenter 20415 notes that the EPA has moved from its initial focus in the 2012 final MATS on one 

element (energy production) to two elements – boiler load and time – to define the end of startup and 

indicates that this is an improvement over the earlier single-element approach. Commenter believes that, 

when considered with the further development of the fuel and emission controls elements of the work 

practice standards, the EPA’s proposed definition of the end of startup is more reflective of the realities 

of boiler operations. However, commenter maintains that focusing solely on boiler load is not 

technically correct or rational because the load at which a boiler reaches stable operations varies widely, 

based on fuel type, furnace and boiler design (combustion method), and operating methodologies. 

Commenter notes that most solid fuel boilers do not reach stable operations until 50 percent load or 

higher whereas some oil and gas fired boilers can function at 20 percent load or less for long duration. 

Commenter states that focusing solely on heat or steam production is likewise unworkable and 

irrational; using that approach, a boiler supplying even a small amount of steam would no longer be in 

startup and would be required at that point in time to engage emission controls. However, commenter

states that according to equipment specifications and established safe boiler operations, a boiler operator 

should not engage emission controls until specific parameters are met.

Commenter 20415 states that the EPA’s more recent thinking – to combine the boiler load or the energy 

production with a period of time increases the adaptability of the rule to a wider range of EGUs. 

Commenter states that this provides a wider compliance margin for boilers that are still operationally in 

startup at 25 percent load or when electricity generation begins, such that they will still be subject to 

work practice standards for 3 or 4 hours after 25 percent load, or 6 or 12 hours after electricity 

generation. Commenter states that the length of time after the load or electricity generation trigger is a 

very important variable for the EPA to adequately account for as many boiler scenarios as possible. 

Commenter states that the greatest flexibility would then be the timeframes at the outer end of those 

under consideration, i.e., 4 hours after 25 percent load or 12 hours after electricity generation. 

Commenter states that if there are boilers that need to operate outside of these parameters, this definition 

will not rationally reflect all regulated boilers and their operational constraints.

Commenter’s 20413 historic plant data reveals that in most startup events the required temperatures 

and/or flow conditions can be reached within 25 percent of nameplate capacity plus 4 hours (actual time 

not Part 75 operating hours) or from the time electricity generation occurs plus 12 hours (actual time not 

Part 75 operating hours), whichever comes first. Commenter notes however, there are instances when 

problems occur during the startup process that will not allow the required temperatures and/or flow 

conditions to be met in order for all of the pollution control equipment to become properly operational 

within the above mentioned time-frame and the EPA final rule must make provisions for such 

occurrences.

Commenter 20428 states that the EPA’s proposed formulation suggests that the Agency may not fully 

appreciate the distinct situations that the different parts of commenter’s definition were intended to 

address. Commenter alleges that under the EPA’s proposed formulation, only during optimal startups 

would all control equipment be operating before startup was defined as ending because both time 

periods under the 3/6 definition would be met at approximately the same time – an EGU would reach

effective pollution controls about 3 hours after 25 percent load is reached, which will be about 6 hours 
20

after first electricity generation (because the EGU, according to the EPA, will take 3 hours to reach 25 

percent load). Commenter maintains that by stripping the two time periods in the definition of their 

independent purposes, the EPA renders the “whichever occurs first” language redundant.

Commenter 20428 notes that the “4 hours after 25 percent load is reached” is intended to recognize that 

at EGUs startup, APCDs are not immediately operational. For example, commenter notes that SCRs are 

not functional until they gradually come up to temperature, and proper scrubber chemistry is not 

established until after electricity generation. Commenter states that startup is not over until the EGU has 

reached normal HAP emissions profile through the operation of fully functional APCD. Commenter 

states the EPA’s data support providing a minimum of 4 hours after 25 percent generation, and not 3 

hours. Commenter cites average SO2 emissions continuing to fall well past 6 hours, further SO2

reductions after 3 hours, NOx emissions continue to fall between 3 and 4 hours, and the EPA’s average 

curve continues to flatten been 4 to 5 hours, meaning SCRs are still not optimally controlling NOx 

between hours 4 and 5. Commenter alleges that, given that many EGUs burning eastern bituminous coal 

will rely on SCRs and scrubbers for Hg control, having a “startup” cutoff of 25 percent capacity plus a 

minimum of 4 hours is of critical importance to compliance for a significant segment of the utility 

industry. Commenter states that one member analyzed a dataset of 232 startups (all part of the CAMD 

data used in the EPA’s Startup TSD) to estimate that during a cold startup for supercritical EGU, the 

time required to achieve NOx reduction well below uncontrolled emissions, i.e., effective control, is 

nearly 7 hours after first reaching 25 percent of gross load. Commenter states Hg emissions data support 

a “4 hours after 25 percent power” test at a minimum.

Commenter 20428 notes the “12 hours after first electricity generation” is intended to deal with 

situations where startup is delayed for unexpected reasons, equipment considerations, or other reasons 

out of the operator’s control. Commenter states that this provision will prevent EGUs from operating at 

low load (i.e., less than 25 percent) indefinitely. Commenter states a 6 hour cutoff is insufficient and 

clearly inadequate. Commenter states that the EPA’s Startup TSD shows that during many startup 

events, subcritical and supercritical EGUs have not even reached 25 percent load 6 hours after 

generation. Commenter notes that supercritical EGUs lag subcritical EGUs by at least 1 hour in attaining 

25 percent power after initial generation. Commenter states the EPA admits that APCD are not fully 

functional when 25 percent load is first reached. Commenter maintains that the EPA’s Startup TSD 

confirms 6 hours after initial generation on “average” is not when pollution controls are fully functional. 

Commenter states that the EPA asserts that average and median NOx emission rates begin to decline 

around hour 6. Commenter notes that pollutant levels for both supercritical and subcritical EGUs 

continue to fall between hours 6 and 12 after first generation, average NOx emissions for supercritical 

EGUs continue to fall significantly between hours 6 and 12, and average SO2 emission for subcritical 

EGUs with dry scrubbers fall noticeably between hours 6 and 12. Commenter states Hg data support 

extending the time period because there are marked spikes in subcritical EGUs in 9 out of 10 startup 

events after hour 6 following initial electricity generation.

Commenter 20428 notes that the “whichever occurs first” language is to ensure that any startup event 

will be as short as possible. Commenter states that it only supports use of the “whichever occurs first” 

language if it functions as originally intended, and its purpose is lost under the EPA’s 3/6 definition.

Commenter 20397 states a one-size fits all definition is inappropriate. 
21

1.1.1.3 25 percent plus 7 or 8 hours

Comment 12: Commenter 20406 suggests that the startup definition allow for at least 8 hours to elapse 

which would allow both stages of the PM controls to be adequately functioning. Commenter notes that 

this period would be in accord with its Title V permit, which allows a startup period of up to 8 hours for 

staged startup of the emissions controls to occur from the synchronization of the EGU to the grid (which 

requires the start of coal firing in the EGU). Commenter notes that after that time, the ACI injection 

must still be initiated. In addition, commenter’s facility utilizes a halogen based sorbent enhancement 

additive (SEA) injected directly into the furnace of the EGU as part of the Hg removal system. 

Commenter states that, as the injection of the SEA can increase halogen acid-gases if it is started prior to 

startup of the wet FGD, the FGD must be brought on-line and stabilized prior to startup of the SEA 

portion of the Hg emission controls. Commenter concedes that it does not always take the full 8 hours to 

achieve operation of all the control equipment, but that time is required when performing a cold startup.

Commenter 20406 maintains that, additionally, large EGUs like those at its facility cannot sustain 

operation at 25 percent of nameplate capacity without supplemental firing of oil or natural gas. 

Therefore, commenter’s EGUs typically attain 25 percent of nameplate capacity within the first 1 to 3 

hours of firing coal. Commenter explains that requiring that startup end within 3 hours of attaining 25 

percent of nameplate capacity is impractical for large EGUs and can substantially shorten the proposed 

time allowed for startup without actually reducing the time required to get all the emissions controls 

operational. Commenter states that the requirement for initiating operation of all emission controls 

related to 25 percent of nameplate capacity must be eliminated or extended to allow startup of all the 

required emission controls. Commenter maintains that if a time period following 25 percent capacity is 

included, then a period of 7 hours following 25 percent capacity must be allowed. Commenter 

recommends that the EPA define the end of startup as “The start of electricity generation plus 8 hours of 

continuous operation” as this gives a definite period and allows adequate startup of large EGUs.

Commenter 20418 recommends the removal of any reference to a strict hour limitation from the 

definition of the end of startup and recommends instead a load value of 25 percent plus 7 hours. 

Commenter states that a startup period solely defined by a certain time allotment after grid 

synchronization cannot account for the various conditions and requirements that must be met following 

specific maintenance activities. Commenter maintains that it is more appropriate to define the end of a 

startup period by the percentage of rated load, providing flexibility during situations where there is an 

unavoidable extended cold start.

Commenter 20418 states that hot starts are the most common type of start and are typically the result of 

processes being slightly out of control causing an EGU trip and that a warm start is often the result of a 

failed component within the boiler itself (such as a tube) that requires repair. Commenter indicates that 

the time period between combustion within the furnace is typically driven by temperature exposure 

concerns, requiring some duration of time to allow the boiler to cool to a temperature that makes it safe 

for employees to perform the appropriate repair. Commenter notes that cold starts (which often are not a 

matter of choice) are typically the result of a maintenance outage in which necessary repairs are made to 

the steam turbines, combustion equipment, and APCDs to correct any operational or performance issues 

and that the time required to successfully control emissions after a cold start is typically longer than that 

of a warm or hot start, primarily due to the numerous safety checks required after such intensive work.
22

Commenter 20418 indicates that cold starts requires several hours, if not days, to get the EGU to an 

appreciable load; these slow starts are costly to the utility because of the low levels of electricity 

generated during these time periods. However, commenter alleges that it is important to maintain the 

slow ramp rate for the health of the equipment, the integrity of the structural materials, and most 

importantly, for the safety of plant personnel.

Commenter 20418 discusses the approach that the EPA used to develop the point to define the end of 

startup as 3 hours after 25 percent load. Commenter notes that the EPA’s analysis only addresses time 

periods in which the average facility begins to indicate that it has achieved a minimum level of pollutant 

control and alleges that this method does not adequately determine the point at which emission rates are 

“well below” uncontrolled levels. Commenter maintains that it is inappropriate to point to the first 

changes in the average trend to indicate that it is appropriate to end startup at that point. Instead, 

commenter states that the EPA must evaluate the point at which emission levels are “well below” 

uncontrolled startup levels. Commenter reviewed the dataset in the proposed rule’s docket and derived a 

smaller data set of only cold starts in order to look at how many hours may be necessary to achieve NOx 

emissions “well below” uncontrolled levels after the EGU has achieved 25 percent of the gross rated 

load. Commenter states that because of the wide variety of start events and scenarios that can be 

incurred, it is impossible to establish a time limit that would be appropriate for every start event, but 

commenter stepped through its analysis and concludes that the end of start-up at a coal-fired EGU 

occurs when the EGU load reaches 25 percent of nameplate capacity plus 7 hours. 

1.1.1.4 25 percent plus 7 hours or generation plus 10 hours

Comment 13: Commenter 20420 states that the EPA should define the end of the startup period as 

occurring when an EGU reaches a steady state controlling SO2 at the MATS emission limit of 0.20 

pounds (lb)/MMBtu. Alternatively, commenter states that the EPA should define the end of startup 

differently for PC and CFB EGUs. Commenter suggests that for PC EGUs, startup should end 7 hours 

after the EGU achieves 25 percent nameplate capacity or 10 hours after the onset of generation, 

whichever occurs later. Commenter suggests that for CFB EGUs, startup should end 13 hours after the 

EGU achieves 25 percent nameplate capacity or 19 hours after initial generation of electricity, 

whichever occurs later.

Commenter 20420 operates its EGUs under the “Start-up and Loading Instructions” (SALI) prepared by 

GE, the manufacturer of its PC and CFB turbine generators. Commenter notes that the SALI requires 

that the turbines heat soak to allow metal temperature equilibration of the crossover and turbine for 60 

minutes after the onset of generation up to or at 2 percent load. This heat soak period is designed to 

prevent temperature mismatch, which is detrimental to the turbine generator sets according to 

manufacturers’ recommendations. Therefore, commenter maintains that per SALI, one hour is required 

during every EGU startup for the turbine soak to be completed before startup may continue.

Commenter 20420 provides an analysis (utilizing the Part 75 diluent cap) of hourly EGU operating data 

obtained from the CAMD database for January 1, 2012, through March 31, 2013, for the four coal-fired 

EGUs at its Spurlock Generating Station (Spurlock) and Unit 2 at Cooper Generating Station (Cooper) 

to determine whether the EPA’s Startup TSD conclusions support actual operating experience with these 

EGUs. Commenter states that the results show that Spurlock 1 and 2 (wall- and corner-fired PC EGUs, 

respectively) achieved 25 percent of the rated nameplate capacity within 3 hours of generation for warm 
23

and hot start events, although both EGUs do not consistently achieve 25 percent of the rated nameplate 

capacity within 3 hours of generation for cold start events. Commenter notes that both EGUs were able 

to achieve 25 percent of the rated nameplate capacity within 4 hours of generation in all cases, however, 

but that the data also show significant variation in the time required to achieve controlled SO2 emissions. 

Commenter indicates that for Unit 1, controlled emissions were achieved within 4 hours of generation 

and within 3 hours of achieving 25 percent nameplate capacity in all cases whereas for Unit 2, the time 

required to achieve controlled emissions varied significantly between all startup events and each type of 

startup. Commenter states that data for cold start events, which require the longest startup duration, 

showed the average time to achieve controlled emissions was approximately 8 hours after generation 

and over 4 hours after achieving 25 percent nameplate capacity. Commenter states that although average 

cold-start duration is comparable to both of EPA’s proposed startup definitions, the range in duration 

significantly exceeds these thresholds and the data show that it may require up to 14 hours after 

generation and 10 hours after achieving 25 percent of the nameplate capacity to achieve controlled SO2

emissions.

Commenter 20420 states that for Spurlock Units 3 and 4 (CFB EGUs) the data show that neither EGU 

typically achieves 25 percent nameplate capacity within 3 hours of generation and achieving this load 

takes much longer than for Units 1 and 2, particularly for cold-start events. Commenter indicates that the 

data for Unit 3 show that up to 12 hours may be required to achieve 25 percent nameplate capacity for 

some cold start events and the data for some cold-starts show that up to 15 hours after the onset of 

generation or 7 hours after the EGU achieves 25 percent nameplate capacity may be required for the 

EGU to achieve controlled emissions. Commenter states that for Unit 4, the data show that up to 20 

hours after generation or 15 hours after achieving 25 percent nameplate capacity may be required for the 

EGU to achieve controlled emissions. Commenter observes that both boilers have identical designs and 

the difference in startup duration between the two boilers highlights the variability in CFB startup 

profiles.

Commenter 20420 states that the SO2 emissions profile for Spurlock 4 for a selected warm-start event 

shows that the limestone feed is engaged approximately 5 hours after the onset of generation; it then 

takes an additional 8 hours for the bed to stabilize and to obtain partially controlled SO2 emissions 

below 0.20 lb/MMBtu. Commenter indicates that the spray dryer adsorber (SDA) is engaged 

approximately 28 hours after startup once the EGU achieves the minimum flue gas temperature after 

which the EGU operates with fully controlled SO2 emissions. Commenter maintains that this example 

clearly demonstrates that the proposed alternative startup definitions do not adequately characterize 

controlled SO2 emissions for a typical CFB startup.

Commenter 20420 states that the SO2 emissions profile for Spurlock 4 for a selected cold-start event 

where the data show that emissions are substantially controlled approximately 44 hours after startup. 

Commenter maintains that this example demonstrates the variability in startup duration for CFB EGUs 

and further illustrates that the proposed alternative startup definitions do not adequately characterize SO2

emissions for a typical CFB startup.

Commenter 20420 states that the results for Cooper 2 (wall-fired PC EGU) were similar to those of the 

Spurlock PC EGUs. Commenter indicates that the EGU achieved 25 percent of the rated nameplate 

capacity within 3 hours of generation for both of the startups evaluated; the data also show significant 

variation in the time required to achieve controlled SO2 emissions – 3 to 13 hours from the onset of 
24

generation or 8 to 13 hours after achieving 25 percent nameplate capacity. Commenter alleges that 

greater variability and duration of EGU startup is expected for this EGU compared with the Spurlock PC 

EGUs and other EGUs equipped with dry FGD because the EGU is equipped with a unique circulating 

dry scrubber (CDS) which has minimum operating temperature requirements similar to conventional 

SDA, although it also requires additional time to establish a stable fluidized bed, which is complicated 

by the dynamic nature of a EGU startup.

Commenter 20420 notes that the EPA Startup TSD concludes that there are no significant differences in 

the startup characteristics of PC and CFB EGUs. Commenter disagrees with this statement based on its 

analysis of emission data from typical operation of the Spurlock EGUs where the elapsed time required 

to achieve initial generation, 25 percent nameplate capacity, and controlled emissions is notably 

different between the PC EGUs (Spurlock Units 1 and 2 and Cooper Unit 2) and the CFB EGUs 

(Spurlock Units 3 and 4). Commenter believes this finding is not surprising considering the fundamental 

differences in operation and the method of SO2 emissions control noting that for Spurlock Units 1 and 2, 

the wet scrubbers begin operation on first fire, and, therefore, begin to provide some immediate 

emissions reduction where limestone injection on Spurlock Units 3 and 4 requires a minimum operating 

bed temperature which is typically achieved only at about 70 MWg for a cold start. Commenter 

maintains that additional time is required to achieve the minimum flue gas temperature necessary to 

engage the SDA, which is typically achieved at about 170 MWg for a cold start event.

Commenter 20420 finds there are two fundamental flaws that contribute to its findings. First, commenter 

believes that the EPA assumes that the SO2 emissions control system stabilizes at each of the proposed 

operating points resulting in emissions that are substantially controlled. Commenter alleges that 

although its data shows that this is generally true for the conventional boilers at Spurlock, it is definitely 

not true for the CFB EGUs, particularly for cold start events. Commenter recommends that the EPA 

consider an alternative approach to selecting the termination of EGU startup based on when the EGUs 

achieve controlled emissions that are below the MATS SO2 emissions standard (in order to remove any 

bias in this analysis, commenter recommends only including data from those EGUs that can meet the 

emissions standard with a 10 – 20 percent margin of compliance). Commenter believes that this 

approach provides a clear indication of when the SO2 control equipment is fully in service that is still 

somewhat conservative because EGUs will operate below this level during normal operation. 

Commenter also concludes that the EPA did not properly characterize variability in the startup duration 

for individual EGUs and between different EGUs. Commenter notes that the EPA’s analysis is based on 

the average values of its sample population, which suggests that half of the startup events are not 

adequately characterized by the proposed operating points. Commenter’s analysis of its data shows that 

the range in startup duration can be significant for individual boilers of the same type, particularly for 

the CFB EGUs. Commenter recommends that the EPA provide further consideration of EGU operating 

variability in selecting the termination of EGU startup. Commenter believes that alternatives could 

include selecting the appropriate range based on the 90th or 95th percentile values or by applying an 

upper prediction limit (UPL) approach similar to the one used in the MATS floor analysis. Based on 

commenter’s findings, it recommends that the termination of EGU startup for PC boilers should be 7 

hours after achieving 25 percent nameplate capacity or 10 hours after the onset of generation, whichever 

occurs later and for the CFB EGUs, the termination of EGU startup should be 13 hours after achieving 

25 percent nameplate capacity or 19 hours after initial generation of electricity, whichever occurs later. 

Commenter indicates that these recommendations are based on the 90th percentile value for the available 

cold start data for each respective boiler type.
25

1.1.1.5 50 percent plus 3 hours or generation plus 9 hours

Comment 14: Commenter 20398 states that the EPA’s end of startup definition would likely pose 

compliance issues for affected facilities. Commenter suggests end of startup at coal-fired EGUs be 

defined as when the affected EGU achieves 50 percent of nameplate capacity plus 3 hours or the start of 

electricity generation plus 9 hours, whichever comes first.

1.1.1.6 Generation plus 12 hours

Comment 15: Commenter 20401 states that the definitions of startup and shutdown incorrectly identify 

their ending and starting points, respectively, because EGU startup does not end at first electric 

generation, and the EPA’s proposed definition of shutdown does not adequately characterize the time at 

which shutdown begins.

1.1.1.7 APCD’s in service

Comment 16: Commenter 20389 supports defining startup to include placing APCD equipment into 

service using manufacturer recommended practices that protect APCDs.

Comment 17: Commenter 5834 expresses general support of the proposed bright-line test (78 FR 

38005) for defining the end of startup, but only if changes are made to Table 3 to subpart UUUUU to 

acknowledge that APCD operation must be phased in until they can be operated in a safe and feasible 

manner.

Comment 18: Commenters 20396, 20397 and 20428 disagree with the EPA’s proposed definition, but 

they did not provide suggestions for other definitions. Commenter 20396 seeks a workable definition of 

startup that is both environmentally protective and allows for safe operation of APCDs. Commenter 

20396 states EGUs cannot comply with the stringent standard unless APCDs are functioning optimally.

Commenter 20397 states the EPA must allow consideration of the nature of the APCD used in 

determining emission limitations, some of which depend on temperature, flow, and/or chemical 

equilibrium to be effective, and recommends that the EPA include startup and shutdown definitions that 

take into consideration distinctions between both the EGU sources and their APCDs. Commenters 

20397 and 20426 note that when defining work practices, the definitions of both the source and control 

device will dictate when “startup and shutdown” periods begin and end, such that compliance with the 

emission limits, which were based mainly on a one-time full load steady state condition, better match the 

conditions utilized when setting the limits. Commenter 20426 notes that although this may make the 

compliance plans for individual EGUs somewhat more complicated, the owners and operators will be in 

a better position to assure compliance and that, because the rule requires monitoring at all times, the 

EPA can request and evaluate whether there are excess emissions during those periods and address those 

conditions on a case-by-case basis.

Commenter 20396 states many APCDs require certain temperatures and pressures in order to achieve 

maximum emissions reductions.
26

Commenter 20428 states that the EPA’s end of startup definition does not provide adequate time for 

APCD equipment to be “set in operation” safely and reliably. Commenter 20398 states that additional 

time is needed for APCD equipment to be operated safely and effectively to meet emission limits. 

Commenter 20405 believes it imperative that the EPA provisions associated with periods of startup and 

shutdown recognize the practical workings of APCD equipment. Commenter 20405 further states the 

rules should ensure the safe operation of the source, control equipment and auxiliary equipment such 

that the owner does not have to endanger plant personnel to comply with startup, shutdown, or 

malfunction (SSM) provisions.

Commenters 20396 and 20408 express concerns that any attempt at a “bright-line” generic rule cannot

safely and adequately address all EGU types and APCD configurations. Commenter 20408 provides 

three examples where having to incorporate the measured concentrations, as required by the current 

definition of end of startup, in the 30-day compliance average will make it even more difficult to comply 

with stringent utility MACT standards and will be compounded if the EGU has multiple startups during 

the 30-day averaging period. Commenter 20408 maintains that the EPA needs to define the end of 

startup as the time when emission controls and boiler system are in stable operation which, typically, is 

dependent on the boiler type; tangential boilers will reach stable load sooner than cyclone boilers.

Commenter 20408 states that cleaning of the internals of boiler tubes and other boiler steam-carrying 

components are required on a periodic basis and that typically the chemicals used in the boiler steam 

handling system cleanings require the cleaning solution to be heated as it is circulated thru the steam 

system which is typically done by heating the boiler with its startup fuel. Commenter indicates that 

under the current MATS rule language, this would be considered a startup even though there is no 

intention for the boiler to generate steam or electricity. Commenter states that additionally at times 

during startup or shutdown a boiler will maintain fire in the boiler but will not generate MW (e.g., where 

you are curing refractory, performing turbine bearing rub outs, or turbine and boiler feed pump testing). 

Commenter states that the EPA needs to specifically exclude such operations from emissions monitoring 

where it is clear that there is no intention to perform a normal startup or shutdown.

Comment 19: Commenter 20404 notes that utilizing a more flexible definition might exclude certain 

EGUs from complying with the rule, and an alternative petition approach should be available to such 

EGUs.

Commenter 20401 agrees with other commenters that using the point when an EGU generates electricity 

as the end of startup is not appropriate. Commenter states that electric generation and startup are two 

distinct processes; start-up ends and operating begins only after the EGU has achieved stable load and 

air quality control devices are properly placed in operation, which is typically well after electric 

generation has begun to occur. Commenter notes that electrical generation typically begins before 

primary air (PA) fans to coal mills are turned on or coal is first introduced and that the introduction of 

coal does not signal that the startup process is over because the EGU is still ramping up in load with 

additional coal mills and associated PA fans being put into service; it is only after these steps have 

occurred and the boiler is in stable operation that startup for the boiler itself has ended. Commenter 

maintains, however, that even at that time, startup of the entire EGU has not ended because additional 

time is needed to achieve safe operating conditions for some emission control devices (i.e., SCRs).
27

Commenter 20401 notes that startup duration can vary significantly, depending on whether the EGU 

goes through a cold startup (e.g., after a long maintenance outage) or a hot startup (e.g., after a short 

outage). Commenter states that in the case of one of its wall-fired boilers, a typical hot startup process 

takes approximately 12 hours – 3 of which are after electric generation has already begun whereas a cold 

startup for this boiler typically takes approximately 26 hours – 8 of which occur after electric generation 

has already begun. Commenter maintains that these estimates do not consider the additional time 

required if boiler equipment issues occur, or if the EGU trips during startup, which is not uncommon. 

Commenter alleges, therefore, that first electric generation is not in reality a true indicator of the end of 

startup and beginning of normal operation.

Comment 20: Commenter 20404 requests the definition of “startup” ensure emissions during these 

periods are minimized to the extent possible in a manner that is consistent with safe and effective 

operation of EGUs and pollution control equipment. Commenter concurs with Commenter 20428’s 

comments that the EPA’s data set for setting the “3/6” option neglects too many outliers in the data set 

which show true operational variability and that the data analysis demonstrates that more time is needed 

to ensure that controls are operating adequately across the range of EGUs to which the generic definition 

of “startup” would apply. Commenter agrees that the definition of startup should be revised to note that 

startup ends 4 hours after 25 percent nameplate capacity is reached or 12 hours after first electricity 

generation, whichever comes first.

Commenter 20408 states that ending “startup” when electricity is first produced does not account for the 

time needed to set the boiler and its associated air pollution control equipment into operation, and that 

the full startup can take 20 hours or more. Commenter provided an informative example of a staged 

startup with a cyclone boiler EGU. Typically, cyclone boilers have 10 - 20 individual cyclones. A 

typical startup procedure for a cyclone boiler is to warm 1 - 3 cyclones using startup fuel and as these 

cyclones come up to temperature the operator begins feeding the primary fuel (e.g., coal). After these 

initial cyclones are on line and using coal the EGU will typically begin generating electricity rather than 

waste this energy in the steam cycle. The remaining cyclones are brought on line in the same manner 

incrementally. The boiler is thus not fully finished with startup until all available cyclones are online 

which could take 20 hours or more for a normal startup. Commenter indicates that the definition should 

reflect the length of time or achievement of operational parameters actually needed to set an EGU into 

stable operation. Commenter states further that it is not to the benefit of an EGU to delay in startup as 

heat rates during startups are 15 - 20 percent higher and, thus, the longer the startup the more energy 

wasted which drives up costs.

Comment 21: Commenter 20393 states that an examination of the historical data in the EPA’s Startup 

TSD for the proposed “one size fits all” approach clearly demonstrates the infeasibility of the EPA’s 

initial proposal of defining the end of startup as being when the EGU first generates electricity for sale 

and, specifically, shows that coal-fueled EGUs, on average, will need much longer periods of time after 

first generation of electricity before they can begin normal operations and properly start up all of its

APCDs.

Comment 22: Commenter 20390 provides several points regarding the EPA’s Startup TSD document. 

Commenter agreed that the EPA correctly identified the three general classifications of startup used in 

the power industry. Commenter notes that in analysis of data in Figures 9, 10, 12, 13, 14, 16, 21, 22, 

etc., the EPA did not appear to analyze the data for each of the three startup conditions separately but 
28

appears to aggregate the startup data. Commenter states the emissions and time limitations should be 

evaluated separately and the EPA did not differentiate startup requirements or timing based on the 

differences. Commenter also notes that the EPA’s “average” start is skewed heavily by hot restarts. 

Commenter states that the EPA should use the upper boundary of the 95 percent confidence levels to 

make certain that plants can comply and not use the average or median to develop conclusions. 

Commenter notes that the quartile data range is significant in every chart and indicates many EGUs 

many not be able to comply with the time limits the EPA proposed. Commenter also notes that several 

consent decrees require NOx emission in the range of 0.05 to 0.07 lb/MMBtu, however data in Figures 

13, 14, 21, and 22 indicate SCRs do not reach these levels. Commenter states that the EPA did a startup 

analysis of SCRs but that they are not integral to MATS.

Comment 23: Commenter 20419 states that the proposed definitions for the end of startup will force 

many EGUs to choose between compliance and risking equipment damage and emissions increases. 

Commenter states that although the proposed definitions for the end of startup in the Proposed 

Reopening are workable for some EGUs, they are impracticable for others. Commenter states that the 

Proposed Reopening states that commenters request that the end of startup be changed to 4 hours after 

25 percent load is first reached, or 12 hours after first electricity generation, whichever occurs first. 

(Commenter notes that this proposed definition does not represent a consensus approach among industry 

commenters.) Commenter states that the EPA alternatively proposes to define the end of startup at coalfired EGUs as occurring at 25 percent of nameplate capacity plus 3 hours, or the start of electricity 

generation plus 6 hours, whichever comes first. As explained in commenter’s prior comments, defining 

the end of startup based on when electricity is first generated will not work at many EGUs due to sitespecific limitations on startup procedures. Commenter maintains its position on this issue. Commenter 

states that these proposed definitions are appropriate for some EGUs but are too restrictive for others 

due to site-specific factors. Commenter states that, as a result, the proposed definition could force many 

EGUs to choose between noncompliance and risking control equipment damage and increased 

emissions, because such EGUs will be unable to start their emissions control equipment safely by the 

end of “startup” as the EPA proposes to define it.

Commenter 20419 agrees with the EPA that certain emissions control devices have specific temperature 

requirements for proper operation. Commenter urges the EPA to consider that, in addition to 

implementation of emissions control devices depending on temperature, the time it takes to reach the 

requisite temperature is different at every plant. Commenter states that although MATS, as finalized, 

allows EGUs to start their “SCRs” and dry scrubbers “appropriately to comply with relevant standards 

applicable during normal operation,” in recognition of this unit-by-unit diversity, it appears that the 

EPA’s proposal to change the definitions for the end of startup could instead require EGUs to put all 

control devices into service at the end of startup. Commenter indicates that the EPA’s Startup TSD

suggests that the EPA believes that SCR and FGD can be put into service 3 hours or less after reaching 

25 percent of nameplate capacity or 6 hours or less following the start of electricity generation. 

Commenter supports the current language in the MATS that allows EGUs to start their SCRs and dry 

scrubbers as appropriate to comply with the numerical emissions limits applicable during normal 

operations. Further, commenter urges the EPA to consider that operation of other types of controls are 

similarly temperature-dependent; certain EGUs are unable to put such controls into service at the end of 

startup as the EPA proposes to define it.
29

Commenter 20419 notes that at certain members’ EGUs, the minimum temperature and air flow 

conditions required for starting SCRs and scrubbers simply are not achieved by the time the EGU

reaches 25 percent of nameplate capacity plus 3 hours, or the start of electricity generation plus 6 hours. 

Commenter states that influencing factors include how long the EGU was down, the ambient 

temperatures, and delays in being able to raise EGU load. Further, certain of commenter’s members’

EGUs are still burning 100 percent natural gas by the time the EGU reaches 25 percent of nameplate 

capacity plus 3 hours, or the start of electricity generation plus 6 hours. Commenter believes that these 

EGUs should not be required to start operating scrubbers when they are still burning only natural gas 

simply because the EPA has defined startup as ending within a certain number of hours; if natural gas or 

another clean fuel is the only fuel being burned, the implementation of control equipment should be 

allowed to be delayed until operating conditions are acceptable to place the control equipment in service. 

Commenter provides an example of 16 startup events over the past 12 months (which included hot, 

warm, and cold startups) where one member’s 3 EGUs have been (1) unable to put scrubbers into 

service by the time the EGUs reached 25 percent of nameplate capacity plus 3 hours, or the start of 

electricity generation plus 6 hours, whichever came first; and (2) unable to put the scrubber into 

operation within 4 hours after 25 percent load was first reached, or 12 hours after first electricity 

generation, whichever occurred first. Commenter alleges that these data confirm that the EPA’s 

proposed definitions for the end of startup are not workable at these EGUs, and that the end of startup 

for some EGUs must be based on temperature instead of hours.

Commenter 20419 maintains that the EPA’s proposed approach unnecessarily risks equipment and 

emissions increases by forcing plant workers to disregard existing plant procedures and start controls 

before it is safe to do so to avoid noncompliance. Commenter states that flowing ammonia to the SCR or 

reagent to the scrubber when temperatures are too low will result in equipment damage and that if dry 

scrubbers are placed into service before the proper temperatures have been reached, the reagent may 

plug the scrubber, rendering the scrubber ineffective and requiring the EGU to shut down to clear out the 

vessel. Commenter notes that at one member’s EGU, the operator must use hot flue gas to warm the 

800,000 gallons of cold lime slurry for several hours before allowing the flue gas to pass through the 

scrubber towers. Commenter states that if it were to allow the flue gas to pass through the scrubber 

towers instead of a by-pass before the slurry reaches the necessary temperature, the cold, moist gas 

exiting the module would turn the stack into a wet stack; because the stack was not designed for wet gas, 

the moisture in the stack would increase the likelihood of corrosion of the stack lining. Commenter 

alleges that starting SCRs or selective non-catalytic reduction systems (SNCR) before the requisite 

temperature is reached also may lead to increased emissions. Commenter further notes that if EGUs 

were required to flow ammonia to an SCR, or ammonia or urea to an SNCR, before the flue gas reached 

the necessary temperature for the reagent to optimally react with NOx, then ammonia slip would 

increase; ammonia slip results in higher emissions of PM2.5 and PM10.

Commenter 20419 acknowledges that particulate control equipment and Hg control equipment may be 

ready to put into service by the time the EGU reaches 25 percent of nameplate capacity plus 3 hours, or 

the start of electricity generation plus 6 hours. Commenter believes that the EPA could address this 

through issuance of a work practice standard for such equipment rather than developing a definition of 

startup that is unreasonable for certain site-specific applications of air pollution control technology. 

Commenter states that the EPA’s proposed definitions would require plants to put controls into service 

before it is technically possible to do so without damaging equipment and increasing emissions. 

Commenter states that the EPA’s one-size-fits-all approach to startup is inappropriate and unworkable 
30

given the broad diversity of plant equipment, pollution control devices, and startup procedures that are 

designed to protect equipment. Comment concludes companies should not have to choose between 

operational safety and noncompliance during startup.

Comment 24: Commenter 20419 urges the EPA to recognize that its own data demonstrate that many 

plants will be unable to comply with the proposed definitions for the end of startup. Commenter states 

that the 3-hour definition is based on average performance of EGUs examined in the Startup TSD, 

meaning that a number of EGUs take longer than 3 hours to implement their emission control devices. 

Commenter states that the EPA should not set a standard that is fundamentally incompatible with the 

operation of certain EGUs. Commenter states that it is technologically impossible for such EGUs to start 

their emissions control equipment any sooner in the startup process without risking equipment damage 

and creating environmental concerns. Commenter states that the EPA has offered no justification for 

developing a proposed definition of startup that a certain percentage of EGUs will simply be unable to 

meet according to the Agency’s own analysis.

Commenter 20419 also believes that the Startup TSD supports identifying a later endpoint for the startup 

process than the one proposed by the EPA. Commenter states that the EPA bases its proposed startup 

definition on the average time it takes for EGUs to begin operating their emission controls, rather than 

the time it takes for control devices to reach removal efficiency consistent with normal operations. 

Commenter states that this guarantees that EGUs will be unable to comply with the emissions limits that 

apply at the end of startup, as the EPA proposes to define it. Commenter states that the Startup TSD

notes that “on average, all types of EGUs in this study...can begin controlling SO2 and NOx emissions 3 

hours or less after reaching 25 percent of nameplate capacity...” Commenter states that the EPA focuses 

its analysis on when emission controls appear to begin reducing emissions, but its own data show that 

emissions continue to trend downward for multiple hours until they reach a steady state. Commenter 

states that accordingly, defining the end of startup as the beginning of the downward trend identified in 

the EPA’s own data and before EGUs enter normal operations will result in many EGUs operating 

above their emission limit for several hours, which would jeopardize compliance. Commenter indicates 

that a 30-day rolling average compliance period may not be sufficient to allow an EGU to operate for 

several hours above its emission limit, particularly if the EGU has more than one startup in a 30-day 

rolling average period.

Comment 25: Commenters 20414 and 20430 note that the EPA’ s 3-hour and 6-hour time frames are 

based on the findings of the EPA’ s Startup TSD, , which commenters believe to be flawed. Commenters 

said that the EPA should not have relied on an average (or median) time of emissions reduction to 

establish the time period to declare the end of startup.

Commenter 20410 notes in the Startup TSD, the EPA states that on average, all types of EGUs in the 

study can begin controlling SO2 and NOx emissions 3 hours or less after reaching 25 percent of 

nameplate capacity or 6 hours or less following the start of electricity generation. Commenter states that 

if the thresholds provided are the average time for an EGU, then half of the time EGUs will not begin 

controlling emissions within the given timeframes. Commenter states that it is not reasonable to 

establish a requirement in a regulation where it is expected that compliance will be met only 50 percent 

of the time.
31

Comment 26: Commenters 20417 and 20419 support the definition of “startup” as “the setting in 

operation of an affected source,” provided that this definition includes the ignition of fuel in the boiler, 

production of steam to begin generating electricity either before or after the primary fuel is added to the 

boiler, and placing in-service the emissions control equipment. Commenters note, “startup” must include 

the requisite time to achieve the temperatures necessary to engage emission control equipment.

Comment 27: Commenter 5840 states that a definition for the end of startup that does not allow for the 

EGU to achieve its normal state of operation with all equipment fully functional will result in the 

inclusion of emissions rates in 30-day averages that are actually associated with startup conditions rather 

than normal (design) operations.

Comment 28: Commenter 20421 expresses concern that the definition of startup does not reflect actual 

boiler operating characteristics of its coal-fired stoker boilers. Commenter shares the principal concern 

of the majority of other commenters that startup does not end when electricity or useful thermal energy 

is produced. Commenter recommends that, to be rational, the end of the startup period must be at a time 

when the boiler operating conditions have stabilized and all APCDs are in service. Commenter defined 

this point as when all associated operator control functions have been completed, the plant is capable of 

steady state operation, normal boiler-related and steam cycle temperatures and pressures have been 

achieved, and all systems normally required for continuous operation have been placed into service. 

Comment 29: Commenter 20401 suggests that the EPA revise the requirement in the final rule that all 

emission control devices, with the exception of limestone injection in FBC EGUs, dry scrubbers and 

selective catalytic, and non-catalytic reduction systems shall operate when coal, solid oil-derived fuel, or 

residual oil is fired. Commenter states that the startup definition in the final MATS rule should be 

revised to account for the time needed for proper and safe operation of air quality control equipment, 

which will, in turn, lead to reduced overall emissions.

Commenter 20416 supports the revised definition for the end of startup, however; the EPA needs to take 

into consideration that the revised startup definition is not specific to all combustion technologies. 

Comment 30: Commenter 20410 suggests the following ways to handle startup and shutdown periods 

in the MATS rule, listed in order of preference:

(1) Commenter states that review the data and set the end of startup based on when a 

significant majority, say 95 percent, of the startups would have all pollution control 

equipment effectively operating, not using the point where the average source will have 

controls on-line (and presumably 50 percent of sources wouldn’t have controls 

effectively on-line). Commenter states that the defined end of startup and beginning of 

shutdown should be used to define when the source must start and end, respectively, 

using emissions data in demonstrating compliance with the MATS limits. Commenter 

states that the regulation should not include provisions that require control equipment be 

brought on line at a specified point in time during startup or remain on-line until a 

specified point in time during shutdown. Commenter states that the fact that startup ends 

at a given point in time and emissions begin to be counted toward compliance with the 

emissions limits will be incentive for sources to get all controls to optimal operation in a 

timely manner. Commenter states that this will serve the purpose of the regulation, 
32

limiting emissions of HAP, but will not force sources to operate equipment in a manner 

that may be unsafe or that may damage the control equipment.

(2) Commenter states that review the data and set the end of startup based on when a 

significant majority, say 95 percent, of the startups would have all pollution control 

equipment effectively operating, not using the point where the average source will have 

controls on-line (and presumably 50 percent of sources wouldn’t have controls 

effectively on-line). Commenter states that the defined end of startup and beginning of 

shutdown should be used to define when the source must start and end, respectively, 

using emissions data in demonstrating compliance with the MATS limits. Commenter 

states that if the EPA determines that the regulation needs to address use of control 

equipment relating to startup and shutdown, it suggests that the following language be 

used:

During or shortly after a startup period, needed pollution control 

equipment shall be engaged as expeditiously as possible, considering 

safety, good engineering practices and manufacturers’ recommendations. 

Shutdown begins when pollution control equipment that is necessary to 

comply with the applicable emission limits under this Subpart are 

disengaged. Needed pollution control equipment shall remain engaged 

prior to shutdown as long as possible, considering safety, good 

engineering practices and manufacturers’ recommendations.

(3) Commenter states that define the end of startup and beginning of shutdown based on 

when pollution control equipment can be engaged or disengaged considering safety and 

manufacturers’ recommendations, as follows:

Startup ends when all pollution control equipment that is necessary to 

comply with the applicable emission limits under this Subpart are 

engaged. Needed pollution control equipment shall be engaged as 

expeditiously as possible, considering safety, good engineering practices 

and manufacturers’ recommendations. Shutdown begins when pollution 

control equipment that is necessary to comply with the applicable 

emission limits under this Subpart are disengaged. Needed pollution 

control equipment shall remain engaged prior to shutdown as long as 

possible, considering safety, good engineering practices and 

manufacturers’ recommendations.

(4) Commenter states that define startup as suggested in bullet item 1 above for purposes 

of defining when emissions are included in the compliance demonstration. Commenter 

states that use the following criteria for engagement of control equipment:

If your EGU is ... 3. A coal-fired, liquid oil-fired, or solid oil-derived fuelfired EGU during startup. You must meet the following ... Once you start 

firing coal, residual oil, or solid oil derived fuel, you must vent emissions 

to the main stack(s) and engage all of the applicable control devices except 
33

limestone injection in FBC EGUs, dry scrubber, ESP, baghouse. DSI, 

SNCR, and SCR You must start your limestone injection in FBC EGUs, 

dry scrubber, ESP, baghouse. DSI, SNCR, and SCR systems control 

equipment systems as expeditiously as possible, but, in any case, when 

necessary to comply with other standards applicable to the source that 

require operation of the control devices.

1.1.1.8 Supercritical EGUs

Comment 31: Commenter 20400 states that startup for supercritical EGUs should conclude at least 6 

hours after an EGU transitions from subcritical to supercritical operation. Commenter notes that there 

are approximately 120 EGUs with supercritical steam generators currently operating and they constitute 

about 90 GWs of the 330 GWs of coal fired EGU capacity in the U.S. and that these are generally the 

most modern and most efficient EGUs in the utility fleet. Commenter states that the EPA’s 

reconsideration proposal and the applicable docket materials still do not properly characterize the startup 

process of a supercritical EGU. Commenter states that although all EGUs have startup activities that 

continue after electricity is first generated, supercritical EGUs also have a very distinct step in the 

startup process where the EGU transitions from subcritical mode to supercritical operation. Commenter 

states that the subcritical mode of operation involves the use of a start-up steam drum or flash tank, 

specialized valving and other equipment to ensure that steam is of high enough quality to prevent 

moisture droplets from damaging the steam turbine. Commenter states that once the EGU transitions to 

supercritical mode, that start-up equipment has been phased out of operation.

Commenter 20400 states that unfortunately the EPA’s analysis in EPA-HQ-OAR-2009-0234-20224

misses the key technical issues associated with a supercritical EGU. Commenter states that the EPA 

does understand the importance of having steam quality high enough to prevent damage to turbine 

blading and other components. Commenter states that the EPA explains in a footnote that “We 

understand that a steam turbine should not be exposed to water droplets at its inlet at any load, to prevent 

blade erosion and other problems, and that boiler/turbine systems are designed to prevent this, and we do 

not consider the proposed definition to be problematic in this regard.” Commenter states that however 

this statement is true for both subcritical and supercritical EGUs during all phases of operation. 

Commenter states that the distinction is in how different EGUs accomplish this requirement.

Commenter 20400 states that in a conventional subcritical EGU, mixtures of steam and liquid are 

returned from the furnace wall tubes and are separated in the steam drum by cyclone separators based on 

their different densities. Commenter states that the steam then passes through separators and driers 

before it leaves the steam drum. Commenter states that it then passes through primary and secondary 

super heaters which superheat the steam well above the saturation point at the operating pressure. 

Commenter notes that it is important to remember that as steam increases in pressure, the saturation 

temperature or point at which water droplets can form will increase. A typical subcritical drum EGU

operates at about 2,400 psia. At this pressure, the saturation temperature is about 662 °F. Commenter 

states that because a subcritical EGU has a separating steam drum followed by super heaters, it is easier 

to assure that the steam generated is of high enough quality to be used in the turbine.

Commenter 20400 states that by comparison, a supercritical steam generator uses a specialized and 

dedicated startup system to operate like a drum EGU when it first generates electricity until a point 
34

much later when it begins the transition to supercritical operation. Commenter states that once that 

transition is completed, the EGU is considered to have completed the major phases of startup. 

Commenter states that at that time the EGU is considered to be in “once through” operation meaning 

that there is no equipment in place to separate out moisture droplets from the steam. Commenter states

that provided it exceeds the supercritical conditions of 3,206.2 psia and 705.40 °F the fluid leaving the 

steam generator will be free of moisture and no separation equipment is necessary. Commenter states

that in normal operation the steam is superheated to 1,000 °F or higher which provides additional 

protection. Commenter notes that the major functions of the startup system were:

• Control water/steam circulation in all sections of the furnace to prevent tubing damage 

due to overheating;

• Provide a means of cleaning and conditioning the feed water;

• Protect the super heater and turbine from thermal shock during startup;

• Providing a heat recovery system during startup and very low load operation;

• Matching the steam pressure and temperature to the conditions needed by the turbine 

during warming, startup, and low load operation; and

• Providing a receiver for overpressure steam after a trip, or during excursions.

Commenter 20400 provides a series of single line drawings that show 11 major steps of a startup for one 

particular supercritical EGU design. Commenter states that the EGU referenced has a gross capacity of 

about 1,400 MW. Commenter notes that individual steam generator manufacturers have different bypass 

system designs. Commenter states that as can be seen by the drawings, the process is rigorous and each 

step must be performed in the proper sequence and there are process conditions such as temperature, 

pressure, fuel flow, and others that must be met before an operator can proceed from one step to the 

next. Commenter states that referring to Attachment 1, the major components of a steam generator start 

up system include the primary and secondary superheater bypass valves, a high pressure flash tank, a 

low pressure flash tank, flash tank return valves, and steam dump valves that lead to a heat sink such as 

an auxiliary condenser. Commenter states that in addition, this steam generator has large division valves 

and sliding pressure valves between the primary and secondary super heater. Commenter states that 

these valves are initially closed when an EGU is started, but are gradually and carefully opened during 

the transition from subcritical to supercritical operation. Commenter states that initial circulation in the 

steam generator occurs in steps 1 through 3. Commenter states that steam generated by a smaller startup 

boiler is used for warming the feed water and the feed pump is started at the beginning of step 4. 

Commenter states that the first firing of fuel in the steam generator occurs at the end of step 4. 

Commenter states that operation of the turbine generator begins in step 7 and electricity is first 

produced. Commenter states that in steps 8 and 9, additional subsystems are placed into service as the 

level of electricity generation increases. Commenter states that the transition from subcritical to 

supercritical operation occurs between steps 10 and 11 and is commonly called “flow transfer.”

Commenter states that once the steam generator completes flow transfer, the startup equipment is phased 

out of operation.
35

Commenter 20400 states that there is a lag of several hours between when the startup system equipment 

ceases operation and when all emissions control equipment is fully operational under normal conditions 

and the EGU’s emissions are representative of normal operations. Commenter states that for example, 

once the flue gas reaches minimum operating temperature, it can take hours to properly warm up the 

large volume of catalyst in an SCR. Commenter states that similarly an FGD system contains a very 

large mass of lime or limestone slurry. Commenter states that often the higher level of excess air during 

startup can drive extra O2 into the slurry and change its chemical nature. Commenter states that 

operators must be careful to prevent conditions that would cause scaling which in turn could foul 

components such as mist eliminators. Commenter states that it again takes time to turn over the large 

volume of slurry and allow the chemistry to reach equilibrium.

Commenter 20400 states that pollution control equipment is also designed to operate most effectively 

within a specified range. Commenter states that the highly variable operating conditions during startup 

(in particular, large swings in temperature, flue gas flow rate, and dew point) may prevent operation of 

some control systems (SCR or sorbent injection) or affect the performance of systems which are in 

operation (scrubbers, ESPs, baghouses). Commenter states that operators often must take care not to 

“over feed” certain systems such as activated carbon to prevent it from accumulating and causing fire, 

pluggage or other risks. Commenter states that all these factors result in higher startup emissions. 

Commenter recommends that the EPA expand the startup period for supercritical EGUs to conclude 6 

hours after an EGU finishes the flow transfer step and completes the transition from subcritical to 

supercritical operation.

1.1.1.9 CFB EGUs

Comment 32: Commenter 20403 states that the suggested language does not address the problems 

related to coal refuse-fired CFB (or FBC)’s as it may take upwards of 24-hours to allow for bed 

stabilization which is a critical aspect of startup as well as initiating procedures and APCDs to insure 

emission requirement are being achieved.

Commenter 20403 disagreed with the EPA’s assumption that the start-up requirements are not affected 

by technology. Commenter states that coal refuse-fired CFB boilers (particularly low Btu, high sulfur 

(on a lb Sulfur/MMBtu basis), high ash coal refuse) are significantly different, than high Btu, low ash, 

and low sulfur (on a lb Sulfur/MMBtu basis) coal. Commenter states that more coal refuse is needed to 

meet the same heat input as coal. Commenter also states that, in addition, if the percentage of sulfur is 

the same, there would be twice as much sulfur delivered to a coal refuse-fired CFB EGU. Commenter 

states that the amount of limestone to control SO2 emissions would, at a minimum be twice as much for 

the coal refuse-fired CFB EGU than for a coal-fired CFB EGU and that the total amount of ash being 

delivered to the boiler would be 3-to-4 times; the net result would be 4 times more ash being delivered 

to the CFB coal refuse-fired EGU than to a coal-fired CFB EGU. Commenter states that, as a result of 

the increase in mass related to the Btu, sulfur, and ash content of the coal refuse and the amount of 

limestone needed to control SO2 emissions, it takes a considerably longer period to produce the load 

needed to sustain and stabilize the bed. Commenter states that based on the limited data collected from 

coal refuse-fired CFB, these considerations were not fully considered in the EPA’s Startup TSD. 

Commenter states that generally, high sulfur coal refuse-fired CFB boilers without back-end SO2

polishing controls can take up to 24 hours to reach stabilized conditions. Commenter notes that these 

time limits are tied to bringing the load up to a point that the bed is stabilized and can be maintained. 
36

The load needed to insure bed stabilization is typically greater than 25 percent. Most coal refuse-fired 

CFB EGUs generally need a load in excess of 60 percent or higher (in the 70 percent range) and once 

such an EGU boiler reaches full load, it usually takes additional time for the bed to stabilize and reach 

optimal furnace temperatures needed to meet the SO2 and NOX emission rates. Commenter alleges that 

if CFB EGUs drop the load below the 60 to 70 percent range, the bed begins to cool below the solid 

firing permissive temperature causing the bed to slump causing the EGU to malfunction or shut down.

Commenter 20403 notes that with back-end SO2 polishing devices (e.g., dry scrubbers or ash reinjection 

with humidification), the CFB boiler is typically designed for about 80 percent SO2 removal and the 

polishing scrubber is designed for about 90 percent SO2 removal for an overall SO2 removal rate of 95 

percent. Commenter indicates that the use of the polishing scrubbers allows the boiler to stabilize its bed 

quicker because less limestone is used in the furnace as less SO2 removal is required and less limestone 

is needed to meet the lower SO2 removal efficiencies.

Commenter 20403 indicates that it has found the key requirement for the start-up of a CFB boiler is bed 

stabilization. Commenter notes that a stabilized bed requires, among other things, the proper particle 

size distribution which allows proper heat transfer rates in the CFB boiler’s various heating zones such 

as the evaporative and/or steam heating zones; once proper heat transfer rates are obtained, the bed 

temperatures become optimal which is required for effective limestone utilization in the removal of acid 

gases and the minimization of NOX emissions. Commenter alleges that this is critical as NOX emissions 

are highly sensitive to both temperature and the amount of limestone present in the bed whereas SO2

removal is highly sensitive to bed temperatures. Commenter maintains that the majority of the bed 

material during start-up comes from the introduction of ash and/or limestone into the furnace where the 

limestone tends to fracture into small particles which, depending on the boiler design, are not optimal for 

heat transfer in the evaporative zone. Hence, according to commenter, the time it takes to create a 

stabilized bed and optimal temperatures is much longer in duration – if too much limestone is added, the 

bed stabilization process becomes stagnant as the bed contains too many fine particles to achieve 

sufficient heat transfer, resulting in even longer time duration to stabilize the bed.

Comment 33: Commenter 20403 states that the coal refuse-fired CFB’s startup period as based on the 

final approved definition and the proposed revised definition would have startup ending before the 

facility is running on solid fuel, its bed stabilized, and the environmental controls, including APCD, to 

address air emissions are brought on line. As a result, commenter alleges that a CFB EGU is in jeopardy 

for having not met its emission requirements and most likely would have violations.

Commenter 20403 indicates that from the data base EPA used to develop the Startup TSD, there appear 

to be two coal refuse-fired CFB EGUs identified (Marion and Westwood), both of both which have 

indicated that it requires approximately 24 hours to bring the EGUs up from cold start safely to being 

operational with a stabilized bed and the emission control processes and devices operational and 

functioning. Commenter alleges that the Startup TSD data appears to be looking at emissions and 

emission compliance, not stable operating conditions. Commenter also alleges that although Westwood 

seems to be able to achieve certain emissions (SO2 and NOX), the data for Marion is less conclusive. 

Commenter notes that the data represents a sequencing of startup fuel and co-firing of startup fuel and 

coal refuse with limestone and/or ash but there is no indication when the co-firing has ceased. 

Commenter believes that the EPA has made the quantum leap to correlate emissions stabilization with 

bed stabilization in a CFB EGU. Commenter maintains that an important aspect of the Marion data is 
37

fundamental to its comments and its reconsideration request. Commenter indicates that CFB EGUs 

(especially those firing higher sulfur coal refuse) are unable to determine an economic and technical 

control strategy to meet either HCl or the SO2 surrogate; to achieve the SO2 surrogate emission rate of 

0.2 lb/MMBtu, the coal refuse-fired CFB EGUs burning high sulfur coal refuse will need to achieve 

upwards of 98 percent capture in the boiler and as such, significantly additional limestone and fuel will 

need to be injected into the CFB EGU and more ash will need to be managed. Therefore, commenter

asserts, it will take more time to stabilize the bed, have adequate fuel and sorbent injected to control SO2

which will result in additional time to bring the other emission control systems/devices online per 

manufacturer specifications.

Commenter 20415 notes that the EPA seeks comment on its analysis of coal-fired EGU startup period 

data, as presented in the Startup TSD referenced in 78 FR 38005. Commenter states that it is unknown to 

what extent the data incorporates the diverse universe of EGUs, but it appears waste coal-fired CFBs in 

particular are under-represented. Commenter states that as reflected in the data and considering the 

potential limitations of the Startup TSD, there are some EGUs that do not complete startup within the 

EPA’s proposed timeframe. Commenter states that the included data appears to support the EPA’s 

conclusions that for coal-fired EGUs, different types of EGUs may be able to reach a certain output in 

some time after start of generation; and they can begin controlling SO2 and NOx emissions in some time 

following the start of electricity generation. Commenter states that thus, many EGUs may be able to use 

a combination of output and time or the start of generation and time as defining the end of startup. 

Commenter states that this type of analysis depends on having adequate representative data available for 

analysis, which was to some extent the case for EGUs with CEMS. Commenter states that therefore, 

based on the data and analysis provided by the EPA, the EPA’s approach using some time following 

output reaching a percent of design capability or time following electricity generation would provide 

compliance certainty and could be applicable to a high percentage of EGUs, if the time is adequate. 

Commenter notes a key issue is the specific values to be used in such an approach.

Commenter 20415 states that the EPA’s data indicates that there are specific EGUs that would not be 

able to meet the conditions proposed by the EPA, for various reasons. Commenter adds, there are other 

EGUs subject to the MATS rule – coal refuse-fired CFBs – whose data does not appear to be included in 

the EPA’s analysis. Commenter states that coal refuse-fired CFBs may take 24 hours or longer to start 

up, based on greater volumes of fuel and longer periods needed for bed stabilization than is the case for 

conventional fuel-fired CFBs. Commenter states that manufacturers provide specifications regarding 

temperatures and timing for these EGUs, fuels, and controls relative to startup and when they are fully 

functional. Commenter states that, also, the refractory thickness in coal refuse-fired CFB EGU is greater 

than conventional fuel-fired CFB EGUs requiring more time to bring up its temperature. Commenter 

states that, for example, a coal refuse-fired CFB cannot typically operate successfully below ~60 percent 

load or the bed begins to slump and not be stable. Commenter states that therefore, using 25 percent 

design capability as a baseline for defining startup is not appropriate or valid as applied to these EGUs. 

Commenter adds, the total volume of material (coal refuse, limestone and ash) to be introduced into the 

bed in order to meet emission limits will extend the time to bring the EGU up to stable effective 

conditions. Commenter states that if the EPA decides to pursue this approach to defining startup of a 

baseline load or capacity measure plus a timeframe, and provides no alternative regulatory path for 

EGUs such as CFBs, then it must consider appropriate baselines and extended periods for specific 

designs/fuels. Commenter states that in the context of the pending 40 CFR 63, subpart DDDDD, rule

(Boiler and Process Heater MACT, Boiler MACT), because there are very diverse designs, fuels and 
38

operating modes utilized by industrial, commercial, and institutional (ICI) boilers and process heaters, 

the alternative unit-specific compliance approach becomes more important for ICI boilers and process 

heaters.

Commenter 20415 states that in order to accommodate those designs/limitations, a more comprehensive 

unit-specific approach is necessary as an alternative compliance method for EGUs that cannot meet the 

proposed EGU capacity/time definition. Commenter states that this is a necessary corollary to the EPA’s 

proposed one size fits all approach with no further flexibility and would be equally environmentally 

protective. Commenter recommends, as it has in the Boiler MACT context, that the EPA revise the 

startup definition to allow facilities an alternative approach to determine the minimum stable operating 

conditions on a unit-specific basis and include the minimum stable operating load that defines startup 

and shutdown and the proper procedures to follow during startup and shutdown in a site-specific plan. 

Commenter states that establishment of the minimum stable operating load on a site-specific basis is 

analogous to setting other boiler and control device operating parameter limits on a site-specific basis. 

Commenter states that this alternative would effectively be the only option for EGUs whose startup 

characteristics fall outside of the EPA’s proposed capacity/time definition of startup.

Commenter 20415 states that the following types of concepts could be used as being indicative of a 

boiler reaching the end of a startup period:

• Boiler firing its primary fuel for a period of time adequate to provide stable and noninterrupted fuel flow, stable and controlled air flows, and adequate operating 

temperatures to allow proper fuel drying and air preheat as applicable.

• Emissions controls in service with operating parameters such as flow rates and 

temperatures being controlled and stable.

• Boiler supplying steam to a common header system or energy user(s) at normal 

operating conditions including pressure, temperature, and above minimum operational 

stable output flow rate, as applicable to the EGU.

Commenter 20415 states that under that alternative approach, boiler owners/operators would establish 

specific operating conditions and parameters defining startup and shutdown in standard operating 

procedures for each affected EGU so that it is clear when each EGU is in either startup or shutdown 

mode. Commenter states that procedures should also be used to guide operations purposely through 

startup or shutdown periods so that protracted periods in startup or shutdown mode beyond that 

envisioned in the procedures are avoided. Commenter states that each startup and shutdown should be 

documented relative to elapsed time and timing of actions prescribed in the procedure so that problems 

are effectively identified and corrected in a timely manner. Commenter states that sources covered by 

the rule are highly variable and the amount of time needed for startup and shutdown may be different 

depending on the specific EGU. Commenter states that the EPA has adopted a source-specific approach 

in other programs, such as Part 75 (40 CFR Part 75 Appendix A 6.5.2.1).

Commenter 20415 states that this alternative approach can be drafted so that “units cannot cycle in and 

out of startup or shutdown” and to provide “clarity regarding which periods of operation are subject to 

the work practice standards rather than numeric emission limits and the associated requirements.”
39

Commenter states that enough specificity would also address the EPA’s concern that startup periods 

must be subject to standards that are more robust than the general duty clause; these site-specific 

parameters would be included in the permit and thereby subject to approval and enforcement.

Commenter 20403 suggests that a requirement that the startup period should end for coal refuse-fired 

EGUs when all emission controls are engaged and the bed is stabilized is the correct approach to address 

the issue of when startup ends.

Comment 34: Commenter 5830 states that the EPA did not adequately consider the issues concerning 

CFB EGUs burning coal refuse in regard to the definition of startup end. Commenter states that the EPA 

should consider startup and shutdown issues for CFB EGUs burning coal refuse separately, as 40 

percent of startup events at CFB EGUs showed extended periods (i.e., 10 - 75 hours) of fossil fuel 

combustion before electricity generation commenced. Therefore, commenter maintains that it appears 

that it is appropriate for the EPA to consider startup and shutdown issues for CFB boilers burning coal 

refuse separately. Commenter also recommends the start of electricity generation for startup purposes

must be due to firing coal/coal refuse.

1.1.1.10 Dry FGD EGUs

Comment 35: Commenter 20423 states that as a general matter it believes the EPA document (EPAHQ-OAR-2009-0234 at p. 14.) describing FGD startup and shutdown operations does not specifically 

describe a separate class of EGUs that are represented by its EGUs with dry FGDs (Antelope Valley 

Station Units 1 and 2; Laramie River Station Unit 3) and includes perhaps as many as a dozen other 

EGUs similarly equipped. Commenter states that dry FGD SO2 control technology uses recycle fly ash 

in fabricating reagent slurry. Commenter states that although this difference does not matter significantly 

for a hot restart, it dramatically alters the cold startup FGD performance as an adequate amount of slurry 

with recycle ash is necessary and the flue gas temperature must be brought up for slurry injection to 

avoid wet ash deposits.

Commenter 20423 states that there is no recycle fly ash available to formulate a slurry mix for several 

hours after a cold restart. Commenter states that the EPA analysis actually does indicate the impact of 

this circumstance in Figure 16 of the Startup TSD. Commenter notes, however, because the analysis 

does not specifically discuss or distinguish between hot and cold restarts the impact is masked by 

averaging hot and cold restarts together. Commenter believes that the EPA needs to modify its technical 

document to include this discussion and analyze the hot/cold startup impacts separately and then modify 

the conclusions and the definition of startup accordingly.

Response to Comments 1 - 35: In the May 3, 2011, proposed MATS rule, the EPA proposed to 

establish numerical standards that apply at all times at EGUs. 76 FR 24976. The EPA received 

comments stating that a work practice standard should be imposed during startup and shutdown periods 

in lieu of numerical standards. In the February 16, 2012, final rule, the EPA finalized a work practice 

during periods of “startup” and “shutdown”, as those terms were defined in that final rule. 77 FR 9304.

The work practice required the use of clean fuels (e.g., natural gas and distillate oil) during startup and 

defined the end of startup as the time the EGU generates electricity or thermal energy for sale or for onsite use. The EPA stated that it saw no technical barriers to burning clean fuels for longer periods if 

necessary to bring the EGU and associated equipment up to temperatures necessary to engage APCDs.
40

77 FR 9304, 9381. EPA also stated its understanding that some EGUs engage all their controls at the 

time they begin generating electricity or thermal energy. But at the same time, the EPA recognized there

may be operational constraints with certain controls (notably dry scrubbers and SCR).

The EPA received petitions for reconsideration of the final startup and shutdown work practice. On 

November 30, 2012, the EPA issued a notice requesting comment on the work practice requirements for 

startup and shutdown periods and on the definitions of “startup” and “shutdown.” The proposed work 

practice requirements and definitions in the November 30, 2012, reconsideration proposal were very 

similar to the startup and shutdown provisions in the February 2012 final MATS rule.

The EPA received numerous comments on the definitions and work practice standards and, based in part 

on those comments, the EPA developed a technical support document (“Startup TSD”) evaluating all 

startup and shutdown events at EGUs based on CEMS information EPA has on SO2 and NOX from the 

Acid Rain Program database. The EPA then made the Startup TSD publicly available (EPA-HQ-OAR2009-0234-20378) and reopened the comment period for the November 2012 reconsideration proposal 

to provide an opportunity for public comment on the Startup TSD and the comments submitted during 

the first comment period. The EPA’s analysis (see Startup TSD entitled “Assessment of Startup Period 

At Coal-Fired Electric Generating Units,” docket ID EPA-HQ-OAR-2009-0234-20378) reviewed hourly 

SO2 and NOX emissions from continuous emission monitor system (CEMS) installations from all of the 

nearly 9,500 distinct startup events at more than 400 coal-fired EGUs, including CFB boilers, and 

subcritical and supercritical pulverized coal boilers equipped with SO2 APCDs (e.g., wet or dry FGD) 

and/or NOX APCDs (e.g., SCR). The EPA analyzed hourly SO2 and NOX emissions primarily because 

the data could be used to determine when sources engaged the controls for those pollutants and that time 

frame would provide a reasonable metric of when to end the startup period and require compliance with 

the numerical standards. We are confident sources will be able to capture and accurately monitor HAP 

emissions at the defined end of startup using continuous emissions monitoring methodologies.

1

In 

addition, we concluded evaluation of these emissions could provide relevant information because SO2

emissions may be used as a surrogate for acid gas HAP and because SCR can impact Hg levels and the 

effectiveness of Hg controls.2 The goal of the analysis was to identify the approximate time it took, on 

average, to initiate operation of APCDs to determine an appropriate end to startup for purposes of 

defining the end of the work practice standard. The goal was not to seek the time it took for APCDs at 

 

1 Sources that demonstrate compliance with quarterly stack testing will not be required to test during the 

period directly after the end of startup under either alternative included in this final rule, and, for this 

reason, we do not find commenters concerns with compliance with the 30-day rolling average well 

founded for those sources using that compliance demonstration method. For sources using CEMS or 

CPMS, the EPA is confident that sources will be able to comply with the 30-day rolling average because 

the final MACT standards contain sufficient variability to include startup and shutdown periods and the 

periods directly thereafter, and because we believe that HAP emissions during those periods, as defined, 

are likely as low as or lower than HAP emissions during other periods, particularly at the best 

performing sources. We are setting a work practice for startup and shutdown because the agency is not 

currently capable of capturing and accurately measuring HAP emissions during that period, not because 

we believe the numerical standards cannot be achieved during the defined startup and shutdown period. 

2 The EPA did not include hourly PM data in this analysis because PM CEM data are not available, but 

we have information indicating that EGUs are able to engage PM controls at approximately the same 

time as coal or oil is added to the unit.
41

all EGUs to become fully operational. The analysis indicated that some EGUs are able to engage all 

their controls once they begin generation, but that a significant majority of EGUs are not able to engage 

all controls at that time. We suggested in the Startup TSD that the end of startup may be at some time 

after the start of electricity generation (i.e., 6 hours after the EGU begins generating power or 3 hours 

after the EGU reached 25 percent of nameplate capacity, whichever comes first).

The EPA received additional comments during the extended comment period both in favor of and 

opposed to the approach suggested in the Startup TSD. Some comments stated that it was not 

appropriate for the EPA to establish the end of startup based on the average time it takes for all EGUs to 

startup, but instead that the Agency should identify the EGUs it believes are the best performing units 

and establish the final standard based on the average time it takes the best performing EGUs to start up. 

Other commenters stated that the EPA erred by considering the average performance of all EGUs and 

instead should focus on the EGUs that take the longest time to complete startup. Considering these 

comments in light of the statute, the EPA finds that its approach in the Startup TSD of looking at all 

EGUs was not consistent with Clean Air Act (CAA) section 112(h)(1) because that provision requires a 

work practice standards consistent with the requirements of CAA sections 112(d) or (f). Because the 

EPA is establishing CAA section 112(d) standards for EGUs for the first time, and not residual risk 

standards under CAA section 112(f), it is appropriate to consider the requirements of CAA section 

112(d) when establishing the work practice standards in this rule. That provision provides that the 

MACT standards for new EGUs must be no less stringent than the performance of the best performing 

similar source and that the standards for existing EGU must be no less stringent than the average 

performance of the best performing 12 percent of sources in the category for categories with 30 or more 

sources or the top 5 sources for categories with less than 30 sources. Although we do not believe we 

have to use the exact same approach to setting work practice standards as we do for setting MACT 

standards, we maintain that the EPA may reasonably follow that approach in light of the statutory 

requirement to establish work practice standards consistent with CAA section 112(d) and the fact that 

the Agency has an almost complete data set for the relevant metric (i.e., information on all startup events 

at units that have the relevant NOx and SO2 controls). Thus, we do not believe the approach of looking 

at the average time it takes all EGUs to engage their controls is consistent with the statute.

The EPA has revised the final rule to include two alternative definitions of the end of startup. First, we 

have determined that it is appropriate to retain the definition of the end of startup that was including in 

the February 2012 final MATS rule. We have information that some existing sources are able to engage 

all control devices (except SCR) at the time they begin generating electricity or thermal energy for any 

use; therefore, we believe that it is appropriate to retain that definition as a compliance option (see, e.g., 

EPA-HQ-OAR-2009-0234-20427). We are also providing an alternative definition of the end of startup 

based on the revised analysis, which we have revised in this final action (see Revised TSD entitled 

“Assessment of startup period at coal-fired electric generating units - Revised” in docket ID EPA-HQOAR-2009-0234) (“Revised TSD”). Specifically, the EPA determined that an appropriate metric for 

identifying the best performing units for purposes of defining the end of startup was to identify those 

units that are able to most quickly engage their SO2 and NOx controls after electricity or thermal energy 

generation begins because we are confident that stack conditions will be sufficiently stable at this time 

for HAP emissions to be accurately measured using CEMS. The EPA revised the analysis in the Startup 

TSD to determine the EGUs that are best performers based on that metric and averaged the time it took 

those EGUs to engage their controls to determine an appropriate time after generation to end startup. See

Revised TSD. We concluded that the best performing EGUs are on average able to get all of their 
42

controls on line within less than 4 hours after electricity generation and we rounded the time up to 4

hours. We determined that incorporating additional variability into the average time, besides rounding 

up to 4 hours, was not necessary because we believe the data we have includes all the startup events at 

the units evaluated in the Startup TSD and Revised TSD.

Many industry commenters state that the times included in the Startup TSD were not sufficient for all 

EGUs to end startup and that the EPA is required to establish a work practice standard that accounts for 

the time it takes all EGUs to complete startup. Several commenters made specific note of the EGUs they 

operate that are not able to comply with the time frames discussed in the Startup TSD. We do not agree 

with the comments. As discussed above, a valid work practice standard under CAA section 112(h) must 

be based on the performance of the best performing units in the category. A work practice that would 

allow all sources to comply with the standard without making any changes to their systems would not be 

consistent with the statute unless all units in the category were identical, which is not the case here

where the record indicates that some sources are able to use clean fuel to sufficiently warm their units 

and others are able to engage all their controls when they begin generating electricity. The definition of 

the end of startup for the work practice standard finalized in this action complies with the statute 

because it is based on the performance of the best performing units as detailed in the Revised TSD.

Concerning the specific EGUs that commenters identified as unable to meet the standards at all time, 

some of the EGUs were not identified by EPA as best performing EGUs for purposes of startup so it is 

expected that those non-best performing sources will have to take some actions at their facility to 

comply with the work practice, whereas others did not provide enough specificity to allow for analysis.

Even best performing sources may be require to make adjustments to and/or operate their EGUs in a 

more efficient and safe manner, as other sources have demonstrated an ability to bring their EGUs, 

including their APCDs, on line safely within the times provided. Whether that is because they have 

greater clean fuel capacity, better tuned equipment, more competent staff, a more efficient or otherwise 

better design structure, or a combination of factors, will be for the source owners to determine and make 

necessary changes at the facility to comply with the requirements. We note that our analysis included all 

types of EGUs (e.g., CFB, sub- and supercritical).

In response to commenters’ concerns that their APCDs may not be functioning as well during and 

immediately after startup, we note that, with the exception of PM controls, the final rule does not require 

sources to operate their controls during startup or immediately following the end of startup. Instead, the 

rule establishes a work practice standard that applies during startup and requires sources to meet specific 

numerical emission limits after the startup period ends. As explained below, these emission limits can be 

met a number of different ways, for example, by continuing to maximize clean fuel usage. The EPA 

believes that maximized clean fuel usage throughout the startup period in conjunction with PM controls

being engaged and operated within 1 hour of primary fuel use will sufficiently offset the HAP emissions 

during startup after coal, residual oil, or solid oil-derived fuel is added to the boiler. We also believe the 

continued maximization of clean fuel use after the initiation of coal, residual oil, or solid oil-derived fuel 

use will be sufficient to offset any lack of efficiency in the APCD that commenters may be concerned 

about during the startup period. In any case, sources will not be required to comply with the numeric 

standards during the startup period. As we indicate elsewhere in this response to comments (RTC) and 

in the preamble, the EPA is establishing a work practice standard for these sources because the Agency

does not have HAP emissions testing data during startup and shutdown periods and, absent that data, we 

are unable to establish numerical standards. We do not know at this time whether the best performing 

EGUs maximizing clean fuels during startup, as defined, are emitting more or less HAP than is required 
43

under the regulation for sources in operational periods other than startup or shutdown, but we believe 

that HAP emission may actually be lower during those periods. In addition, our HAP continuous 

emissions monitoring methodologies are not certified to accurately measure HAP emissions during the 

defined startup and shutdown periods. After startup ends, sources that are concerned about compliance 

because they are unable to address efficiency issues with their controls or other facility specific 

problems may continue to burn clean fuels with the primary fuels to minimize HAP emissions during 

those periods. Furthermore, we believe that any additional HAP emissions that may occur after the 

startup period ends will be offset over the 30-day averaging period, as we explained in the MATS 

record. Sources will need to determine the necessary adjustments to their equipment and/or work 

practices (e.g., increased clean fuel capacity) to comply with the rule requirements.

Several commenters said that the EPA erred by not evaluating cold, warm, and hot starts separately for 

purposes of defining startup because the cold start units will take longer to get up to the temperatures 

necessary to engage controls. We do not agree with the comments and have not included a separate 

analysis based on the status of the EGU at startup for the following reasons. The work practice standard 

requires EGUs to startup their units on only clean fuels until the EGU begins combusting coal, and 

startup ends 4 hours after electricity generation. We recognize that cold units will have to combust clean 

fuels alone for a longer period of time in order to get their systems up to the temperature necessary to 

ensure that the EGU will be able to complete startup within the defined time. Commenters did not 

provide much if any information questioning the technical ability of EGUs to warm their systems on 

clean fuels alone, though the comments do indicate that some EGUs do not currently have sufficient 

clean fuel capacity to bring their units up to the necessary temperatures. Those units will likely have to 

increase their clean fuel capacity or otherwise modify their units to ensure that they can bring their 

boiler and APCDs up to a temperature that will allow them to comply with the final standards at the end 

of startup, if they believe they are unable to comply with their current system.

3

In the Startup TSD issued during the reconsideration for startup and shutdown, the EPA suggested 

defining the end of startup, as 6 hours after the start of electricity generation or 3 hours after a coal-fired 

EGU reaches 25 percent of nameplate capacity, whichever occurs first. In other words, 6 hours after the 

start of generation or 3 hours after reaching electricity generation equal to 25 percent of nameplate 

capacity, whichever comes first, an EGU would have to start monitoring and reporting its HCl, PM, and 

Hg emissions for the purpose of calculating whether it is in compliance with the 30-day average 

emission limits. This approach was intended to provide sufficient time to initiate the operation of 

APCDs, and to provide a reasonable time to ensure that EGUs could reasonably capture and accurately 

measure HAP emissions with continuous emissions monitoring systems such that a work practice would 

no longer be warranted.

 

3 The EPA is aware that some coal-fired EGUs subject to MATS have the ability to operate at full 

capacity on natural gas, and that others have requested 1-year extensions to the compliance date for the 

purpose of increasing their clean fuel capacity through installation of natural gas pipelines, gas 

conditioning equipment, and/or new igniters and warm-up guns. See, e.g., “Significant Revision of Part70 Source Operation Permit” for the Weston Plant dated September 23, 2014, in docket ID EPA-HQOAR-2009-0234 (p. 5: “B02 is capable of operating at full load on natural gas.”); EPA-HQ-OAR-2009-

0234-20438.
44

As stated above, the EPA received many constructive and detailed comments on the analysis. Although 

commenters’ opinions varied, the EPA identified three distinct groups of comments. The first group 

agreed with the EPA’s approach to define a time limit following the start of generation, but many 

commenters suggested that more time was necessary to safely and/or fully engage APCDs. The second 

group (noted later in this document) proposed that CAA section 112 requires the EPA to establish 

standards based on the average of the best performing 12 percent of EGUs, not the average of the fleet. 

The third group disagreed with the EPA’s approach, stating that many APCDs could not be fully 

functional within the time limits specified by the EPA, and citing the need for greater flexibility.

In the Revised TSD issued with this final rule, the EPA developed an analysis of distinct startup events 

that took place at 414 EGUs during a 2-year period. The analysis shows the time and operating 

characteristics required for EGUs to control emissions using APCDs. The analysis was divided into two 

parts. The first portion analyzed the startup events at all the EGUs with the relevant data. For the second 

part, we determined that the EGUs that, on average, were able to engage their APCDs the fastest are the 

best performing sources for purposes defining the end of startup for this rule, and we looked at the 

startup events at those EGUs. We selected the units that were able to most quickly engage their controls 

because we determined that such units were likely the most efficient sources and would likely begin 

controlling their HAP emissions sooner and more effectively than sources that took longer to engage 

their controls. The data indicate that the sources that are engaging their controls are significantly 

reducing their NOX and SO2 emissions so we are confident that the controls are working at least 

moderately well by the end of startup.4 We are also confident that sources will be able to accurately 

measure HAP emissions with CEMS at the end of the startup period.

The EPA evaluated the information provided by commenters and considered the different approaches to 

defining the end of startup. It is important to remember that the hour at which startup ends is the hour at 

which compliance with the numeric limits begins, but sources are not in fact required to operate any 

specific control other than PM controls at this time as long as the sources are able to comply with the 30-

day rolling average under the operating mode at the time. Therefore, EGUs must collect and report all 

required emissions and heat input or generation data necessary to demonstrate compliance with the 

numerical limits that take effect following the end of startup. These data are used in calculating whether 

an EGU is in compliance with the 30-day average emission limits. The final rule does not mandate that 

all APCDs be fully operational at the end of startup. As stated above, the EPA chose to define the end of 

startup as the time it takes for APCDs to become operational at the best performing EGUs. The EPA 

chose this option because it believes it most closely follows the requirements of CAA section 112(h), 

which requires work practice standards consistent with CAA sections 112(d) and (f), and because we are 

confident that sources will be able to capture and accurately measure HAP emissions at the end of the 

startup period.

The EPA’s analysis of startup events at coal-fired EGUs indicates that the best performing EGUs can, 

on average, initiate operation of their SO2 and NOX APCDs within 4 hours following the start of 

generation (see Revised TSD), and these are generally the controls that take the longest to engage. 

Therefore, the EPA has chosen to include an alternative definition of the end of startup as the end of the 

 

4

Instead of using the alternate equivalent SO2 emission limit, sources have the option of complying with 

the HCl limit which, based on our information, is easier to remove than SO2.
45

4

th hour following the start of generation of electricity or useful thermal steam for use for any purpose.

The EPA notes that this definition is broadly applicable to different types of EGUs.

The EPA is also finalizing a revised work practice related to the PM control devices that applies to the 

EGUs complying with the alternative definition of the end of startup. In the February 2012 final MATS 

rule and in the November 2012 reconsideration proposal, the EPA stated that once an EGU starts firing 

coal, residual oil, or solid oil-derived fuel, all of the applicable control devices had to be engaged (with 

certain listed exceptions). See, e.g., 77 FR 9304, 9381. The listed exceptions did not include controls for 

PM emissions and, thus, the EPA’s intent was that PM controls would be engaged (i.e., operational) at 

the moment electricity is generated, which generally coincides with the time coal, residual oil, or solid 

oil-derived fuel are fired. We did not receive comments making us question the ability of most EGUs to 

engage their PM controls quickly after generation, but there were comments suggesting that there may 

need to be some flexibility. For this reason, we are providing a 1-hour period of time following the 

initiation of firing of coal, residual oil, or solid oil-derived fuel before PM controls (including FGD 

systems if an EGU is able to effect PM control through this APCD) must be engaged. Therefore, we are 

finalizing as part of the alternative work practice that PM control must be engaged within 1 hour of the 

time coal, residual oil, or solid oil-derived fuel are introduced into the boiler. We have also added 

requirements to document that PM control is being achieved through the operation of the PM controls.

In response to comments that EGUs subject to the Acid Rain Program are already required to define the 

EGU’s ranges of operation and normal load (see 40 CFR Part 75, Appendix A, section 6.5.2.1) and that 

startup and shutdown for such EGUs under MATS could easily be based on these ranges of operation, 

we considered this provision early on but discarded it. The minimum safe stable load in Part 75 is 

arbitrarily set by the source to enable the identification of an operational load range for the EGU. Based 

on this operational range, Part 75 requires that certain QA tests (mostly relating to flow) be conducted at 

several levels within that range. This works very well for these QA tests in Part 75 and we have not 

changed our position on this provision as it applies to Part 75. However, because this range is arbitrarily 

set by sources and not enforceable, we did not think that it would be adequate for defining periods of 

startup and shutdown under MATS.

The EPA notes that the SCR is not the main control device for Hg, but it will likely facilitate removal by 

oxidizing a portion of the Hg. However, we analyzed NOX (and NOX controls) because we have data on 

all startup events, NOX is measured with CEMS, and the NOX controls are often the last controls to be 

engaged, not because of the potential to help remove Hg. NOX control is an indicator of the end of EGU 

startup. In addition, because our analysis shows that SCR achieve at least 20 percent NOX reduction at 

the best performing EGUs by the end of startup, some Hg oxidation will be occurring and this will 

facilitate subsequent removal in the FGD. As with SCR, the FGD controls at the best performing EGUs 

are reducing the SO2 emissions by at least 20 percent and also reducing acid gas HAP as well as PM and 

Hg. We do not agree that spike concentrations directly after our defined end of startup, to the extent they 

may occur, are likely to cause EGUs to violate the MATS limits. As we have indicated elsewhere in the 

record, we maintain that the standards contain sufficient variability to account for spikes in emissions, 

particularly when averaged over a 30-day rolling period.

The data available to the EPA indicate that, on average, EGUs begin firing coal at about 10 hours after 

the start of fossil fuel combustion. That does not mean they rapidly transition to 100 percent coal and 

commenters have not indicated that they cannot continue to fire clean fuel for longer periods. Further, on
46

average, electricity generation begins at about 8 hours after the start of fossil fuel combustion and, on 

average, FGD-controlled EGUs’ SO2 emission rates are 85 percent lower than SO2 emissions at 

uncontrolled EGUs at the start of electricity generation. We believe that these data indicate that many 

sources are able to bring their SO2 controls online prior to the introduction of coal, solid oil-derived fuel, 

or residual oil.

Finally, the EPA acknowledges the comments asserting safety issues that must be considered during 

startup of PM controls (e.g., carbon monoxide (CO) buildup, fabric blinding). We believe that almost all 

EGUs will be able to alter their source through any number of means, including increasing clean fuel 

capacity and modifying burners or fan systems, and comply with the final work practice requirements; 

however, we recognize that there may be rare occasions that preclude a viable compliance option.

Therefore, we are finalizing a provision that provides that an owner/operator may apply for an EGUspecific case-by-case emission standard consistent with 40 CFR 63.6(g). However, the EPA will only 

consider such requests for EGUs that can provide evidence of a documented manufacturer-identified 

safety issue and can provide proof that the PM control device is adequately designed and sized to meet 

the final PM emission limit and that it is not feasible to make changes at the facility to otherwise address 

the identified issue. In its request for the case-by-case determination, the owner/operator must provide, 

among other materials, documentation that: (1) the EGU is using clean fuels to the maximum extent 

possible to bring the EGU and PM control device up to the temperature necessary to alleviate or prevent 

the safety issues prior to the combustion of coal or oil in the EGU, (2) the EGU has explicitly followed 

the manufacturer’s procedures to alleviate or prevent the safety issue, (3) the source provides details of 

the manufacturer’s statement of concern, and (4) the source provides evidence that the PM control 

device is adequately designed and sized to meet the final PM emission limit. In addition, the source will 

have to indicate the other measures it will implement to limit HAP emissions during periods of startup 

and shutdown to ensure a control level consistent with the final work practice requirements

The final rule allows affected EGUs to use the definition of startup that was in the February 2012 final 

MATS rule (i.e., that startup ends when electricity generation begins) for all pollutant emissions.

Alternatively, the end of startup may be defined as 4 hours after the hour in which electricity generation 

begins. Further, 40 CFR 63.6(g) allows the owner or operator to petition the Administrator for an 

alternative definition, in cases where, for valid technical and/or safety reasons, additional startup time 

may be needed.

We address comments related to common stack issues in section 1.2.5 of this document.

With regard to commenter’s note that a quotation used by the EPA in the Startup TSD that comes from a 

chapter entitled “Oil and Gas Utilization” being inappropriate as it does not apply to oil-fired EGUs, the 

EPA has deleted use of this reference.

Commenters also noted maintenance activities that required heating the boiler with no intent of 

producing electricity. As long as these activities are done with clean fuels alone, the EPA believes the 

EGUs are being compliant with the rule even if there is no intent to startup. In addition, if a failed 

startup occurs before generation plus 4 hours, then the EGU would not have reached the end of startup 

when the numeric emissions apply; however, the source would have to restart its EGU on clean fuel 

alone. Our analysis took into consideration startup data from most EGUs, including EGUs that perform 

hold points.
47

The EPA recognizes that to meet the standard some EGUs may need to operate their controls differently 

from previous practices (e.g., EGUs may need to start more FGD modules than they currently use during 

EGU startup). Not every plant will have the capacity to comply with the work practice without making 

some modification to the affected EGUs, and a standard that resulted in sources doing nothing more than 

current practice would almost certainly not be compliant with the requirements of CAA section 112(h). 

To comply with this final rule, sources will need to have sufficient clean fuel capacity to bring their 

EGUs to a temperature sufficient to bring PM controls on line, and this amount of heat has been shown 

sufficient at other facilities to bring all controls on line before introducing coal, solid oil-derived fuel, or 

residual oil. Sources will have to evaluate their system to determine what modifications will be 

necessary to comply with the final work practice standard.

1.1.1.11 Use of SO2/NOx Data

Comment 36: Commenters 20400 and 20428 state that the EPA’s Startup TSD inappropriately uses SO2

and NOx emissions data and not HAP data to judge when a startup should conclude. Commenters state

that the EPA analyzes NOx and SO2 emissions of EGUs to support its conclusion that startup should be 

defined as ending 3 hours after 25 percent power, or 6 hours after initial generation of electricity, 

whichever occurs first. Commenter 20400 states that SO2 is a surrogate for the HAP acid gas emissions 

regulated under MATS, however EGUs are not required to use it; instead they can opt to measure and 

comply with HCl directly. Commenters state that NOx emissions are not subject to regulation under the 

rule. Commenters note that the EPA’s analysis does not plot Hg emissions, and does not explain if/how 

the NOx emissions that it has chosen to analyze correlate with Hg. Commenters state that similarly, the 

EPA does not analyze PM emissions, which serve as a surrogate for the non-mercury metal emissions 

regulated by the MATS. Commenters maintain that the EPA is therefore attempting to draw general 

conclusions about HAP emissions during startup based on incomplete HAP data.

Commenter 20428 attempted to fill this information gap by analyzing Hg CEMS and PM CEMS data, 

but with noteworthy constraints. Commenters 20400 and 20428 state that the practical reality is that 

because the compliance date for the MATS rule is not until 2015, few sources have Hg CEMS installed 

that follow the protocols of the MATS rule. Commenter 20428 notes that the limited Hg CEMS data it 

reviewed presents a somewhat different picture than the SO2 and NOx data reviewed by the EPA. 

Commenter 20428 reviewed emissions information obtained during 10 separate startups of a 500 MW 

subcritical coal-fired boiler that has an SCR, cold-side ESP, and wet FGD. Commenter 20428 alleges 

that in all but one of these startups, the EGU had elevated Hg levels well after 6 hours after first 

electricity generation. Commenter 20428 notes that it also analyzed PM CEMS data during startup and 

indicates that the challenge with that analysis is that PM CEMS are not correlated during startup and 

shutdown and, thus, the data they produce are of questionable reliability. Nonetheless, Commenter 

20428 maintains that the PM data suggest that startups can extend well beyond 6 hours after first 

electricity generation (which would no longer be “startup” under the EPA’s suggested 3/6 definition), 

particularly for EGUs sharing a common stack.

Commenter 20400 states that this failure to consider the emissions of pollutants regulated under the 

MATS introduces uncertainty into the EPA’s analysis and supports providing additional flexibility in 

defining the end of startup. Commenter 20428 notes that the limited data used in the EPA’s Startup TSD 

introduce uncertainty into the analysis and support providing additional flexibility in defining the end of 
48

startup. Commenters 20400 and 20428 state that based on the SO2 and NOx data that the EPA does 

have, it is obvious that there is certainly variability in NOx and SO2 emissions during startup. 

Commenters state that the EPA has generated smooth curves to plot out “average” performance in its 

figures, but these curves “obscure” the inherent variability in how each EGU starts up. Commenters note

that close review of the box-and-whisker plots in many of the figures shows the wide variation of the 

data points. Commenter 20428 maintains that this startup variability is confirmed by comparison of an 

individual EGU’s emissions during startup events. Commenter 20428 alleges that there is an additional 

uncertainty in the SO2 and NOx control information presented in the EPA Startup TSD. Commenter 

20428 states that the technical analysis does not explain whether these data compilations include 

emissions data from facilities where EGUs share a common stack; the inclusion of common stack data 

for an EGU startup, where other common stack EGUs were already operating, could skew the emissions 

performance data and indicate earlier emissions control than would be the case had the other EGUs (and 

their associated control equipment) not been operating. Commenter 20400 states that the EPA’s Startup 

TSD is flawed because it analyzes SO2 and NOx performance and asserts that performance of those 

emissions is the basis for determining a startup period under MATS.

Commenter 20400 states that Hg emissions cannot be characterized by looking at SO2 and NOx 

emissions. Commenter states that by not specifically analyzing Hg emissions during startup, the EPA’s 

analysis misses another important point. Commenter states that many EGUs will use additional materials 

to aid in Hg removal. Commenter states that these include sorbent injection systems such as ACI, FGD 

additives to control Hg re-emissions, and other chemical agents to aid in the oxidation of elemental Hg. 

Commenter states that although these additives are effective at normal operating conditions, they are not 

during startup conditions. Commenter states that ACI for example has been well documented to require 

a minimum gas velocity to properly disperse the material into the flue gas. Commenter states that if ACI 

is required for Hg emissions control, Commenter’s position is that it cannot be placed in operation until 

the EGU load has reached at least 25 percent of full load. Commenter states that this is necessary among 

other reasons to prevent fires in the air heaters and ESP hoppers.

Commenter 20400 states that the EPA’s analysis has an additional deficiency in that it did not consider 

the impact of startup on the output based limits. Commenter states that startups by their very nature 

result in less efficient operation. Commenter states that the amount of fuel required to generate a unit of 

electricity during certain phases of a startup may be 25 percent to 40 percent higher than during normal 

full load operation. Commenter states that a higher fuel consumption rate during startup compounds 

with a lower HAP removal efficiency to produce an even higher emission rate using the output based 

limits as compared to the heat input limits.

Commenter 5833 thinks it inappropriate to choose the performance of NOx controls when

determining a startup period for controls of PM and other MATS pollutants – the SCR controls NOX on 

larger EGUs and is not put into service until it reaches half of its full load output (in accordance with 

manufacturer guidelines concerning minimum temperatures) to avoid making wet ammonia deposits 

downstream in the air heaters and ductwork which would damage the equipment and make it necessary

to take a plant off line.

Response to Comment 36: The EPA is establishing a work practice for periods of startup and shutdown 

because the Agency does not have data on HAP emissions from those periods. Moreover, accurate HAP 

data from those periods is unlikely to be available from either emissions testing (which is designed for 
49

periods of steady state operation) or monitoring instrumentation such as CEMS (which are designed for 

measurements occurring during periods other than during startup or shutdown when emissions flow are 

stable and consistent). Even though the CEMS data may not accurately reflect HAP emissions during 

periods of startup or shutdown, the data are useful in showing emission trends relative to emission 

control device operation.5 As shown in the figures provided by commenters, PM and Hg emissions 

generally decrease in the hours after initial generation as control devices come online. The work practice 

requirement to start on clean fuels and maximize the use of those cleans fuels throughout the startup 

period is designed to minimize HAP emissions during those periods, but sources are not required to 

comply with the numerical limits during startup and shutdown.6Integral in the step of developing the 

work practice is determining the point at which startup ends and EGUs must comply with the numerical 

limits. The EPA’s analysis of the time it takes the best performing EGUs to engage their SO2 and NOx 

controls provides a reasonable gauge as to when startup ends, because those controls are generally the 

last to come on line because of the operating requirements (i.e., requiring a higher flue gas temperature, 

the use of slurry obtained from the PM APCDs) and we are confident that emissions can be captured and 

reasonably measured at this time. Sources are not required to comply with the numerical limits during 

startup and shutdown. For this reason, the EPA does not need HAP emissions data for purposes of the 

work practice standard EPA is finalizing.

The rule has added an alternative definition of startup (see 40 CFR 63.10042): this new definition (2) 

includes additional reporting, monitoring, and recordkeeping requirements for those EGUs without PM 

CEMS or not having LEE status. Should an EGU owner or operator choose to employ this new 

definition, collection and reporting of this information will provide additional detail regarding startup 

conditions; this detail will help establish whether or not additional revisions to startup definition (2) 

and/or work practices may be required. Of course, an EGU owner or operator may continue to rely on 

startup definition (1), which has not changed. Reliance on definition (1) means no additional costs, 

whereas selection of definition (2) may cause a minimal increase in costs for monitoring, reporting, and 

recordkeeping. See the additional requirements in 40 CFR 63.10020(e)(3) and 63.10030(e)(8).

The rule also allows EGU owners or operators who choose to use definition (2) and who have 

demonstrated concerns about safely engaging and operating PM control(s) within 1 hour of first firing of 

coal, residual oil, or solid oil-derived fuel, to submit requests for alternative non-opacity emissions 

standards. Such requests are subject to notice and comment rulemaking per 40 CFR 63.6(g)(1). Until 

 

5 Commenters did not provide actual data; rather, charts summarizing data from six PM CEMS were 

provided. The PM CEMS are identified by commenter as being certified but no means of checking that 

claim were provided. Commenter notes that “absolute accuracy” of PM CEMS cannot be attested 

“because the instruments are not correlated (calibrated) during such periods of operation [startup or 

shutdown].” Strictly speaking, neither NOx nor SO2 CEMS are calibrated at the levels found during 

startup or shutdown; rather, they are calibrated between a range of values expected to be seen during 

non-startup and shutdown periods. What these instruments can provide during these periods is an 

indication or trend of emissions, rather than actual values. Of course, the trends are impacted by use (or 

non-use) of diluent caps, as shown in the graphs provided by the commenter.

6 Sources that demonstrate compliance with either a sorbent trap or CEMS are required to collect data 

during startup and shutdown, but the data are not used for compliance purposes. The EPA is collecting 

data during these periods so that it will have startup and shutdown HAP data when it reviews the rule 

pursuant to CAA sections 112(d)(6) and (f).
50

promulgation in the Federal Register of the final alternative non-opacity emission standard, an EGU 

owner or operator shall comply with definition (1) of startup contained in 40 CFR 63.10042. See the 

details in 40 CFR 63.10011(e)(4).

The EPA’s analysis considered the best performing sources at the EGU level, not the sector level. The 

analysis included common and multi-stack configurations.

The EGU is responsible for meeting either input-based or output-based standards (this is a decision for 

owner/operator) during periods other than startup and shutdown because we believe HAP emissions can 

be accurately measures at these times. This includes periods of operation at lower loads and the 

standards have been set to account for variability associated with all periods, including startup and 

shutdown periods and low load periods that may occur as the EGUs are ramping up after the end of 

startup.

See the response to comments 130 and 131 related to the time to engage PM APCDs.

1.1.1.12 Failed Starts

Comment 37: Commenter 20415 states that the rule should also address this possible circumstance: an

EGU reaches 25 percent load and continues startup, then drops below 25 percent load before the end of 

the startup period. Commenter states that in that situation, the full 3 or 4-hour time allowance should 

recommence, once 25 percent load is again reached, as the EGU would need to recommence each phase 

of the startup process. Commenter believes clarity on this point in the regulation would provide 

compliance certainty.

Comment 38: Commenter 20423 states that a startup failure can conclude with shutdown occurring 

within the proposed allowed startup time, or the startup failure can extend beyond the proposed allowed 

startup time. Commenter states that, as pointed out in the Startup TSD the EPA submitted in this 

rulemaking docket and of which the EPA requests comment, “...failed starts occur for a variety of safety 

and operating reasons.” (at p. 4.) Commenter questioned whether a startup failure that concludes within 

the proposed time for startup might still present compliance issues with respect to this proposal?

Commenter 20423 states that even a series of failed startups can necessitate EGU operation beyond the 

proposed time for startup to end in the definition. Commenter states that, as the EPA identified on the 

final paragraph of page 4 of the Startup TSD there are many reasons for combustion to cease prior to the 

“completion of startup” as suggested by the EPA definitions. Commenter states that it is unclear, both in 

the technical paper and in the EPA’s explanation in the proposed reconsidered rule, whether the EPA

intends this cessation of combustion prior to the completion of a startup to “end” the startup or merely 

“stay the startup clock” until the resolution of the “reason” for the interruption is satisfied. Commenter 

asks the EPA to clarify its intent in this situation.

Comment 39: Commenter 20409 states that the definition of “failed start” should be clarified such that 

a startup ends when EGU combustion ceases. Commenter states that a startup failure can end with a 

shutdown occurring within the proposed allowed startup time, or a startup failure can extend beyond the 

proposed allowed startup time. Commenter states that, first, as pointed out in the Startup TSD, “...failed 

starts occur for a variety of safety and operating reasons.” Commenter states that as it understands the 
51

proposal, a startup failure that concludes within the proposed time for startup would not present 

compliance issues with respect to this proposal. Commenter asks whether this supposition is correct. For 

clarity, Commenter requests the EPA to restate its position that a failed start within the proposed startup 

time period poses no compliance issues for HAP SSM.

Commenter 20409 states that the EPA’s Startup TSD recognizes many reasons for combustion to cease 

prior to the “completion of startup” as startup is defined in the proposed HAP SSM definition. 

Commenter states that under the proposal the EPA presumably would classify situations where 

combustion ceases during a startup as a “failed start,” whereas many in the industry would define an 

attempted startup where combustion ceases as an “interruption” during startup. Commenter states that 

although it presumes the EPA intends to end startup when combustion ceases and thus a “failed start”

has occurred, it is not clear from the EPA’s Startup TSD or from the HAP SSM proposal whether the 

EPA intends this cessation of combustion prior to the completion of a startup to “end” the startup or 

merely “stay the startup clock” until the resolution of the problem for the interruption is found and 

combustion is again started. Commenter states that it is imperative that under the proposal a startup ends 

when combustion ceases prior to startup completion, resulting in a “failed start” where the clock stops 

and the startup ends.

Commenter 20409 states that as noted by the EPA, the normal progress of startup activities may involve 

the cessation of fuel combustion following the initial combustion of ignition or startup fuel. Commenter 

reiterates that many in the industry would call these “interruptions.” Commenter states that as a practical 

matter “interruptions” may include planned or unplanned multiple stop/starts of the combustion process. 

Commenter notes that planned interruptions may include, for example, establishing stable igniter 

operation and flame safety safeguard systems, proof of boiler and/or turbine interlocks, chemical 

cleaning operation, initial turbine warming, and turbine shakedown operations including those for safety 

and insurance purposes. Commenter adds that unplanned interruptions may include, for example, sudden 

and unexpected flame stability problems; temperature and/or pressure excursions; and unavoidable 

operational equipment problems with fans, air heaters, and pumps, for which normal stable expected 

operational ranges have not been achieved. Commenter states that unplanned interruptions may also 

include unexpected tube leaks which may take multiple days to repair.

Commenter 20409 states that its members have experienced planned and unplanned interruptions in 

startups ranging in duration from a few hours to multiple days. Commenter states that one member 

references four occasions within the 2-year 2011-2012 study period of startups used in the EPA’s 

Startup TSD where a major coal-based EGU startup sequence was interrupted between one and three 

times before the EGU reached normal operation. Commenter states that the interruptions ranged 

between 1 hour and 4 hours; in all but one case, the interruption occurring events arose before coal fuel 

to the boiler had been established. Commenter states that but in that one case, coal combustion was 

initiated and terminated without startup. Commenter states that in a separate prolonged shutdown 

situation following an EGU trip (and while using natural gas fuel), an exhaustive troubleshooting 

exercise was conducted to isolate an electrical problem on the plant control system; several days were 

required to rectify the problem once the source was identified. Commenter states that in this occasion 

coal combustion was not initiated prior to the “interruption” but it is quite plausible to envision 

circumstances where coal combustion could have commenced followed by an interruption, where 

several days would be required to correct underlying problems. Commenter states that under these or 
52

similar circumstances, it is imperative that when combustion ceases, the startup ends with a failed start 

and the startup clock ends rather than being stayed.

Comment 40: Commenter 20409 states that the startup rule should clearly incorporate the “malfunction 

defense” where unforeseen failures cause startup to exceed the time limit allowed for startup. 

Commenter states that although not detailed in the EPA’s Startup TSD, the data supplied show failed 

starts can and do exceed the time proposed to end startup under unexpected or unavoidable 

circumstances. Commenter believes the affirmative malfunction defense contained in 40 CFR 63.10001 

is and should be applicable to these events to avoid noncompliance penalties. Commenter notes the 

definition of “malfunction” contained in 40 CFR 63.2 to be used in 40 CFR 63.10001 references “...not 

reasonably preventable failure of...process equipment, or a process to operate in a normal or usual 

manner which causes, or has the potential to emission limitations in an applicable standard to be 

exceeded.” Commenter believes the 40 CFR 63.3 malfunction definition in combination with the 

affirmative malfunction defense on 40 CFR 63.10001 is available to avoid noncompliance penalties for 

startup failures that exceed the proposed startup time. Commenter requests that the EPA clarify its 

position on failed starts that exceed the proposed time period.

Comment 41: Commenter 5831 notes that a startup failure can conclude with shutdown occurring 

within the proposed allowed startup time, or the startup failure can extend beyond the proposed allowed 

startup time. Commenter indicates that, as pointed out in the Startup TSD, “...failed starts occur for a 

variety of safety and operating reasons.” Commenter asks if a startup failure that concludes within the 

proposed time for startup might still present compliance issues with respect to this proposal.

Commenter 5831 notes that even a series of failed startups can necessitate EGU operation beyond the 

proposed time for startup to end in the definition. Commenter indicates that, as identified in the Startup 

TSD, there are many reasons for combustion to cease prior to the “completion of startup” as suggested 

by the EPA definitions. Commenter states that it is unclear, both in the technical paper and in the EPA’s 

explanation in the proposed reconsidered rule, whether the EPA intends an end of combustion prior to 

the completion of a startup due to a failed startup to “end” the startup or merely “stay the startup clock”

until the resolution of the “reason” for the interruption is satisfied. Commenter asks for clarification.

Response to Comments 37 - 41: Under the final rule, a failed startup event restarts the startup clock if 

the source ceases all combustion before beginning a new startup event. The source would be required to 

combust only clean fuels to begin the new startup. Units that begin a startup event that fails before 

electricity is generated and coal, residual oil, or solid oil-derived fuel is added will similarly not be in 

jeopardy of noncompliance with the standards because the clock will not have started in that situation.

Commenter does not specify the conditions but the EPA believes the examples where tube leaks need to 

be repaired would necessitate cessation of fuel firing and/or generation (i.e., a shutdown) and, thus, not 

be included within the startup period.

Concerning the comment on the affirmative defense, we note that on April 18, 2014, the U.S. Court of 

Appeals for the District of Columbia Circuit vacated an affirmative defense provision analogous to the 

provision included in the final MATS rule for the numerical standards. Natural Res. Def. Council v. 

EPA, 749 F.3d 1055 (D.C. Cir. 2014). In light of that decision, the EPA does not believe it can provide 

an affirmative defense provision with respect to the startup and shutdown work practice. The EPA will 

evaluate any such occurrence on a case-by-case basis.
53

1.1.1.13 NSPS

Comment 42: Commenter 5848 states that the November 2012 definition for startup was vague and 

needs clarification. Commenter states that it is not appropriate to end startup when the EGU first begins 

to generate any electricity, or when the EGU first makes thermal energy for industrial, commercial, 

heating, or cooling purposes, whichever is earlier. Commenter supports the June 2013 definition because 

it is consistent with commenter’s operating experience with its biomass-fired boilers. Commenter states

that the definition is also consistent with commenter’s Title V operating permit definition of the end of 

boiler startup. Commenter provides revised language:

Startup means the period in which operation of an EGU is initiated for any purpose. 

Startup begins with either the first-ever firing of fuel in an EGU for the purpose of 

producing electricity or useful thermal energy (such as heat or steam) for industrial,

commercial, heating, or cooling purposes or the firing of fuel in an EGU for any purpose 

after a shutdown event. Startup ends 6 hours after when the EGU starts to generates

electricity that is sold or used for any other purpose (including on site use), or 3 hours 

after the EGU achieves 25 percent of nameplate capacity while makesing useful thermal 

energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes 

(16 U.S.C. 796(18)(A) and 18 CFR 292.202(c)), whichever is earlier.

Commenter 5848 also provides an alternative definition that could apply to all EGUs or, at the EPA’s 

discretion, be limited to biomass-fired EGUs only:

Startup means the period in which operation of an EGU is initiated for any purpose. 

Startup begins with either the first-ever firing of fuel in an EGU for the purpose of 

producing electricity or useful thermal energy (such as heat or steam) for industrial, 

commercial, heating, or cooling purposes or the firing of fuel in an EGU for any purpose 

after a shutdown event. Startup ends when the EGU generates electricity that is sold or 

used for any other purpose (including on site use), or the EGU makes provides useful 

thermal energy (such as heat or steam) at the proper pressure, temperature and flow rate 

to a common header system or energy user(s) for use as either process steam, or for 

motive power (steam-driven equipment), or for industrial, commercial, heating, or 

cooling purposes (16 U.S.C. 796(18)(A) and 18 CFR 292.202(c)), whichever is earlier.

Response to Comment 42: This comment was submitted to the NSPS docket (EPA-HQ-OAR-2011-

0044) but is similar to comments presented above submitted to the NESHAP docket (EPA-HQ-OAR2009-0234). Therefore, the responses provided to those comments also apply to this one. We would note 

that a biomass-fired boiler that does not meet the definitions in 40 CFR 63.10042 would not be subject 

to 40 CFR Part 63, subpart UUUUU.

1.1.1.14 Definition of Startup - Other

Comment 43: Commenter 20428 states that the EPA focuses on normal or average startups and fails to 

capture the unpredictability and variability in how any given EGU starts up. Commenter 20428 states

that characterizations of startups as “normal” suggests that it is predictable and consistent event, but it is 
54

not, even on well-operated and maintained EGUs. Commenters 20395, 20396, and 20428 state that 

every startup is unique. Commenter 20428 states that startups for a given EGU can vary based on (1) 

length of time EGU has been down; (2) testing or other needs for specific equipment during startup; (3) 

equipment glitches; (4) unexpected ambient conditions; and (5) natural variability of fuel characteristics. 

Commenter 20428 notes that because EGU startups require thousands of individual yet interrelated 

components and dozens of subsystems to be “set into operation,” if even one component or subsystem 

fails to operate as intended, the entire startup process for an EGU can be delayed. Commenter 20428 

cites examples of issues that cause startups to exceed the times in the EPA’s definition, including: water 

chemistry hold; turbine differential expansion; turbine crossover soak; and testing of equipment 

following an outage.

Commenter 20428 states that plant personnel monitor water chemistry closely during startup and when 

out-of-limit water chemistry parameters are detected, the boiler will be held at current load/steam flow 

while water treatment facilities purify process water (i.e., a water chemistry hold). Commenter states

that water sample collection and analysis requires approximately 1 hour and 2 to 4 hours if multiple 

samples and adjustments are made. Commenter states that following boiler chemical cleaning or a long 

period of shutdown, a water chemistry hold can last 12 hours or longer. Commenter states that as 

temperatures and water flows increase during startup, water impurities can plate out on the turbine, 

degrading EGU performance and efficiency, and corrode boiler tubes, leading to boiler tube failures. 

Commenter 20428 states that during startup, operators carefully monitor and control heating of 

rotational and stationary turbine metal, as different parts of the turbine heat up at different rates; for 

example, turbine rotors heat up faster than the shell. Commenter states that if load is increased too 

quickly, the rotor metal will expand quicker than the stationary shell metal, closing gaps between 

rotating and stationary components, leading to vibration issues or turbine trip. Commenter notes that to 

prevent excessive stress cause by differential expansion of the metal of different turn parts, the boiler 

must often hold at low load (e.g., 5 percent of capacity) for 2 to 3 hours to allow the machine to stretch 

slowly before the EGU proceeds to next step; this is common for cold starts. Commenter states that a 

turbine trip requires resetting the process, which could take another 8 hours, prolonging startup

(although the turbine may trip in this event, in order to maintain boiler temperature, boiler combustion 

may not be halted).

Commenter 20428 states that manufacturers require turbine crossover soak on all cold startups, where 

steam piping from intermediate pressure (IP) and low pressure (LP) sections of the turbine are allowed 

to heat to the proper temperature. Commenter states that total soak time is usually 3 to 4 hours, and the 

time required varies based on initial turbine and crossover metal temperature and is dictated by starting 

and loading charts provided by the manufacturer; for example, holding at 5 percent electricity generation 

load until crossover temperature reaches 350 °F (it may require 2 to 3 hours to reach 350 °F) and then 

hold for 1 hour. Commenter states that if load is increased too quickly, a fracture in crossover steam 

piping is likely.

Commenter 20428 stated that when equipment or parts are changed out during a maintenance outage, 

testing must occur when the EGU brought back online to ensure the equipment is working properly and 

optimally. Commenter provides as an example when pulverizer coal piping is replaced during an outage 

period, coal line balancing must be performed. Commenter states that a boiler may have seven or eight

pulverizers and each pulverizer may have up to eight coal lines, and each pulverizer must be tested 
55

separately and each coal line must be tested to ensure even distribution of combustion in the boiler; thus, 

testing of a single pulverizer can take 6 to 8 hours. Commenter maintains that before an EGU can be 

brought to full load following this type of work, each pulverizer must be separately tested; some of this 

testing can be performed prior to bringing the EGU back online, but some testing necessarily must occur 

with coal flowing through the piping. Commenter states that startup process and time following 

electricity generation prior to 25 percent load can easily require much longer than 6 hours. Commenter 

provides as another example vibration issues following maintenance work, when replaced/repaired parts 

interact with existing parts for the first time. Commenter states that if vibration is detected, plant 

personnel must perform diagnostics to determine whether the vibration level is acceptable, and the EGU

may be held at low load (less than 25 percent) for as long as 12 hours. Commenter states that if vibration 

level is unacceptable, special analysis and calculations are required at this reduced state.

Commenter 20428 states that characterization of startups as “normal” suggests that any given EGU’s 

startup is a predictable and consistent event – it is not; even well-operated and maintained EGUs will 

often have protracted startups due to the type of situations commenter provides. Commenter provides an 

attachment with figures of NOx emissions from four EGUs from the CAMD database (for subcritical 

and supercritical EGUs) over a number of startup events that demonstrate the variable nature of the 

startup period, even for a given EGU.

Response to Comment 43: As stated above, the EPA maintains that its analysis of the startup practices 

of the top performing EGUs, which included all types of EGUs, and its final definition of “startup” 

adequately balance commenters’ concerns with the requirements of CAA section 112(h). The definition 

of startup accommodates protracted startups and provides flexibility for dealing with “out-of-theordinary” startup events. The requirement to maximize the use of clean fuels during the startup period 

(which may mean burning more clean fuels and for a longer period of time) will assist in safely bringing 

the necessary equipment up to operational temperatures – while minimizing emissions of HAP. Further, 

if the boiler and/or turbine generator “trips” during a startup period and the EGU is no longer generating 

electricity, the startup process and time periods begin anew when the EGU begins generating electricity 

again. However, if electricity generation began before the “trip,” the shutdown work practices would be 

applicable. The work practice requirement of engaging and operating the PM APCDs within 1 hour of 

coal, residual oil, or solid oil-derived fuel firing remains in effect regardless of whether electricity is 

generated.

Comment 44: Commenter 20403 states that the EPA Startup TSD did not deal with the differences 

between coal and coal refuse or bed stabilization but were instead fixated on emissions. Commenter also 

states that the startup analysis for the EGUs analyzed in the document was premised on its existing 

permits and not on requirements that will be imposed under MATS.

Commenter 20403 states that the EPA Startup TSD does not reflect startup under the MATS rule, when 

additional controls will be implemented in starting up the facility.

Response to Comment 44: As noted above, the analysis included in the Revised TSD follows 

CAA section 112, which requires that the standards be based on the practices of the top 

performing existing sources for which EPA has emissions information.
56

The EPA has chosen to define the end of startup as the end of the 4th hour following the start of 

generation of electricity or useful thermal steam. The EPA notes that this definition is broadly 

applicable to different types of EGUs and EGUs in our analysis currently have control 

configurations that will allow them to comply with the final work practice standard.

Comment 45: Commenter 20403 suggests wording for the startup definition, using one of two concepts 

as follows:

Concept No. 1 “Startup means the period in which operation of an EGU is initiated for 

any purpose. Startup begins with either the first-ever firing of fuel in an EGU for the 

purpose of producing electricity or useful thermal energy (such as heat or steam) for 

industrial, commercial, heating, or cooling purposes or the firing of fuel in an EGU for 

any purpose after a shutdown event. Startup ends when the EGU generates electricity 

that is sold or used for any other purpose (including on site use), or the EGU makes 

useful thermal energy (such as heat or steam) for industrial, commercial, heating, or 

cooling purposes (16 U.S.C. 796(18) (A) and 18 CFR 292.202(c)) as a result of being 

fired on solid fuel (coal or coal refuse) in a stable operational mode, whichever is 

later,

-ORConcept No. 2 “Startup means the period in which operation of an EGU is initiated for 

any purpose. Startup begins with either the first-ever firing of fuel in an EGU for the 

purpose of producing electricity or useful thermal energy (such as heat or steam) for 

industrial, commercial, heating, or cooling purposes or the firing of fuel in an EGU for 

any purpose after a shutdown event. Startup ends when the EGU generates electricity 

that is sold or used for any other purpose (including on site use), or the EGU makes 

useful thermal energy (such as heat or steam) for industrial, commercial, heating, or 

cooling purposes (16 U.S.C. 796(18) (A) and 18 CFR 292.202(c)), and the unit is 

operating in a stable mode burning coal or coal refuse.”

Commenter believes that by using the concept of a “Stable Bed,” a standard would be established which 

would allow APCD or process controls to start as soon as technically feasible and not “at all times 

during startup” as previous written; table 3 also addresses the concern of limestone injection in coalfired CFBs allowing that to happen and addresses the need to bring on other APCDs or process controls. 

Commenter states that the manufacturers have established permissive temperatures when APCD should 

be started along with other criteria and that all APCD should be able to meet their permissive 

temperatures in the time allotted under the proposed “end of startup” language related to bed 

stabilization.

Comment 46: Commenter 20393 states that it is unclear whether the new definition will only apply to 

the exclusion of data for purposes of calculating the 30-day rolling average emissions rates, or whether it 

will also apply to the work practice standards for operating ESPs and other APCDs. Commenter 

suggests that the EPA should expressly confirm that the new definition of startup does in fact also apply 

to work practice standards so that coal-fueled EGUs will not be required to operate their APCDs until 

the end of startup under commenter’s suggested new startup definition. Commenter maintains that the 
57

rationale for the same relief in both cases is that coal-fueled EGUs will encounter the same technical 

feasibility and safety concerns regarding their compliance with the work practice standards and their 

calculation of the 30-day emissions limitations.

Comment 47: Commenter 20407 states that the startup period should be defined to conclude only when 

the EGU as a whole is in operation. Commenter concurs with many of the comments provided on this 

reconsideration, in that the startup of an EGU is not complete until fuel is being ignited in the boiler, 

steam and electricity are being generated, and the operating conditions of the EGU meet the criteria for 

safe and technically feasible operation of all “APCDs” associated with the EGU. Commenter reiterates 

its original comments to the November 30, 2012, proposed rule, in that the emission standards 

established by MATS were based on the EGU, including all APCDs, operating in a normal manner. 

Commenter states that until such time that an EGU’s operating parameters allow for safe and technically 

feasible operation of the APCDs, the EGU should be considered in startup mode, as it is not being 

operated in a manner with which the standards were established.

Commenter 20407 states that as expressed by several commenters in reconsideration comments, an EGU 

experiences significant economic losses while in a startup condition, both in actual costs, due to the 15 -

20 percent decline in heat rate, and in the loss of electric sales. Commenter states that this provides the 

EGU with a significant incentive to complete the startup in the most expeditious manner within the 

safety and operational boundaries of the specific EGU.

Comment 48: Commenter 20404 supports the concerns and technical assertions of the EGU industry 

commenters regarding the definition of startup, particularly with regard to when “startup” ends and the 

technical impracticability for EGUs to comply with the definition as written in the February 16, 2012, 

rule.

Comment 49: Commenter 20413 supports the idea of keeping flexibility in the final rule’s startup 

definition by allowing one or the other definitions.

Response to Comments 45 - 49: The EPA based its definition of the end of startup on the performance 

of the units EPA identified as the top performing 12 percent of EGUs. The top performing group

included all types of EGUs, and the final definition of the end of startup adequately balances 

commenters’ concerns with the requirements of CAA section 112(h). The EPA similarly looked to the 

units we defined as best performers when determining the other requirements applicable during startup 

and shutdown.

Comment 50: Commenter 20425 states that additional flexibility in the startup definition is warranted 

due to the fact that the EPA’s Startup TSD does not address Hg and PM emissions and NOx emissions 

(considered in the EPA’s analysis) are not regulated by MATS. Commenter notes that the EPA’s 

assessment is based on an average of hot, warm, and cold startups combined and that there are 

conditions and challengers that are unique based on the startup conditions (hot, warm, or cold) due in 

part to the amount of time that systems have been shutdown, maintenance work performed, and the time 

frame involved to bring systems up to design operating conditions. Commenter notes that, again, 

additional flexibility in the startup definition is warranted.
58

Response to Comment 50: See Response to Comment 36. In addition, as shown in the Revised TSD 

analysis, the best performing sources with respect to NOx and SO2 emissions were those whose control 

devices were operational within 4 hours. The EPA also maintains that the best performers are able to 

engage their PM control devices within one hour of coal, solid oil-derived fuel, or residual oil 

combustion. The analysis looked at hot, warm, and cold starts individually and found 4 hours after 

electricity generation to be a common time in which emissions control devices began to be effective for 

any type of start. Although NOX is not a HAP, control for NOX can impact Hg levels and, in any case, 

the EPA determined it was appropriate to consider NOX controls in its analysis because those controls 

are often the last to be engaged, not because of their ability to facilitate Hg removal.

Comment 51: Commenter 5840 asks if in the proposed definition of the end of startup, “nameplate 

capacity” means the capacity included in the EIA 860 report for each individual EGU.

Response to Comment 51: The term “nameplate capacity” is not used in the definition of “startup” 

contained in the November 30, 2012, proposed rule. Therefore, the EPA is unclear as to commenter’s 

intent and we are unable to respond.

Comment 52: Commenter 5840 asks for clarification on the startup and end of startup definitions when 

two boilers (e.g., individual FBCs) that start separately, operate individually, and have emissions 

monitoring equipment on their own stack, but share a turbine/generator. Commenter notes that the 

startup of the second boiler while the first is generating electricity will need to be contemplated 

differently in terms of when numerical limits apply to the second stack; the second boiler has 

temperature thresholds that must be achieved prior to adding limestone to the fluidized bed and the 

effective use of the APCD. Commenter indicates that the EPA should clarify that the definitions of 

startup and end of startup are to be applied to individual boilers in cases where an FBC has two boilers 

that can startup and shutdown independently of each other and have separate stacks.

Response to Comment 52: The EPA agrees that the definitions of startup and shutdown apply to 

individual, separate EGUs which can startup and shutdown independently and which have individual, 

separate stacks, but share a generator or turbine, provided that the EGUs have individual, separate 

monitoring systems. The EPA notes that for those EGU owners or operators who choose to demonstrate 

compliance with a generation-based standard, appropriate means to determine electrical generation for 

each EGU will need to be provided. 

Comment 53: Commenter 20428 states the EPA could exempt startup periods from reporting.

Response to Comment 53: The rule retains the monitoring, recordkeeping, and reporting requirements 

associated with startup and shutdown periods, and includes additional requirements. As explained in the 

preamble to the February 2012 final rule,7collection of startup and shutdown data will provide the EPA

with information to more fully analyze the ability and appropriateness of establishing numeric emissions 

standards and operating limits during periods of startup or shutdown so the issue can be addressed as 

part of the ongoing 8-year review of the rule. Collection of these data as part of the rule will also serve 

to reduce, if not eliminate, future ICRs on this topic. Finally, we intend to use the data to evaluate, to the 

 

7

See 77 FR 9382 (February 16, 2012).
59

extent possible, the accuracy of HAP CEMS during periods of startup and shutdown and determine 

whether it is feasible to establish numerical limits at a later time.

Comment 54: Commenter 20408 states that the ICR data used to develop the MATS rule did not 

include data collected during a startup or shutdown, and that all testing was performed at normal EGU

loads where all APCDs were operating normally. Commenter indicates that the EPA, in its assessment 

of startup periods in EPA-HQ-OAR-2009-0234-20378, states “...that average and median NOX emission 

rates for the full range of normal starts at SCR-equipped supercritical PC EGUs begin to decline around 

hour 6, indicating that, on average, SCR effectively controls NOX approximately 6 hours or less after the 

start of generation.” Commenter believes that this statement is very misleading and states that, e.g., 

(referring to Figure 13) although at hour 6 NOX begins to decrease, it does not reach a stable (and 50 

percent lower) level of control until about 20 hours after startup. Commenter indicates that this stable 

level of control is what was tested as part of the 2010 ICR and the emission rates that the MATs rule 

were based on and states that startup should not end until the boiler and air pollution control equipment 

operating conditions are reached as was tested in the 2010 ICR.

Response to Comment 54: The EPA believes that the analysis of the startup practices of the top 

performing 12 percent of EGUs, and its final definition of the end of startup adequately balance 

commenters’ concerns with the requirements of CAA section 112(h). The EPA notes that the goal of the 

analysis was to identify the approximate time it took, on average, to initiate operation of APCDs by the 

top performing 12 percent of EGUs. The goal was not to seek the time it took for APCDs at all EGUs to 

become fully operational. The EPA believes that EGUs will be able to reasonably capture and accurately 

measure HAP emissions at the end of startup because of the expected emissions flow and also be able to 

comply with the numerical limits as discussed above and in the preamble to the final rule. In addition, 

sources that want an additional compliance margin may also continue to co-fire clean fuels after the end 

of startup to further minimize HAP emissions. The EPA believes that sources almost always operate 

with a compliance margin to ensure continuous compliance with numeric standards. The fact that 

sources are generally able to operate with a compliance margin is further evidence that EPA’s MACT 

standards are achievable and contain sufficient variability to absorb spikes in HAP emissions that may 

occur.

1.1.2 Definition of shutdown

Summary of Comments Received Following November 30, 2012, Proposal

Comment 55: Commenter 20281 notes that although it is in favor of expanding the time defining 

startups, this is not necessary for shutdown periods.

Response to Comment 55: The EPA thanks the commenter. Considering the comments received, the 

EPA did not consider it necessary to change the proposed definition for shutdown periods.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 56: Commenter 20404 requests shutdown be defined as the period 12 hours before last 

electricity generation because when an EGU is brought out of steady state for shutdown, the air 
60

pollution controls lose effectiveness in a reverse fashion as temperatures and pressures drop requiring 

the disengagement of control equipment.

Commenter 20408 notes that from an APCD perspective SCRs and ACI systems will be in shutdown 

mode well before electricity generation ceases and fuel is shut off to the boiler (e.g., for an SCR, the 

ammonia will be shutoff once the inlet temperature falls below the critical temperature for normal 

operation; for the ACI system, injection will cease once the boiler falls below its minimum stable load to 

avoid safety issues with the ESP). Commenter notes that in both of these situations, electricity is still 

being generated and fuel is being supplied to the boiler. However, the control efficiency for NOX and Hg 

begins dropping at this time as these control systems are not operating in their normal mode. These 

conditions were not tested as part of the 2010 ICR so commenter requests that the beginning of 

shutdown be defined as that point in time when the required control devices are not operating in their 

normal manner as part of a shutdown sequence and that the EPA should not define a bright line for when 

shutdown begins. 

Comment 57: Commenter 20403 states concern about the combustion of residuals in the bed once the 

fuel feed has been stopped. Commenter states that combustion residuals in the bed will have unburned 

coal refuse/carbon that will continue to combust even though no fuel is being fired. Commenter states

that a suggested temperature (lower bed temperature < 500 °F) may address this concern. Commenter 

provides the following suggested text:

Shutdown means the period in which cessation of operation of an EGU is initiated for 

any purpose. Shutdown begins when the EGU no longer generates electricity or makes 

useful thermal energy (such as heat or steam) for industrial, commercial, heating, or 

cooling purposes or when no coal, liquid oil, syngas, or solid oil-derived fuel is being 

fired in the EGU, whichever is earlier. Shutdown ends when the EGU no longer 

generates electricity or makes useful thermal energy (such as steam or heat) for industrial, 

commercial, heating, or cooling purposes, and no fuel is being fired in the EGU.

Commenter 20421 recommends that the definition for shutdown be clarified to “no...fuel is being fed to 

the EGU” from the current “no...fuel is being fired in the boiler.” Commenter notes that although in 

some EGU technologies, the term “fired” is synonymous with the term “fed,” EGUs utilizing stoker 

technology will still have combustion of fuel residuals on the grates for a period of time after the fuel 

feed has stopped.

Comment 58: Commenter 20401 states that the proposed definition of “shutdown” does not accurately 

reflect the point at which shutdown begins. Commenter explains that “shutdown begins at the point 

where igniters are placed in the boilers for flame stabilization to support cessation of the primary fuel 

source,” and recommends that the definition of “shutdown” should be revised to reflect the actual time 

at which shutdown begins.

Comment 59: Commenter 20413 states that the controlled shutdown process, a shutdown that is not 

caused by equipment malfunction, for its cyclone boiler is a process of gradually taking all systems, 

including pollution control equipment, down until the boiler is no longer operating. Commenter states

that the coal combustion process begins slowly to be reduced which in-turn reduces the load MW 

generated. Commenter states that the required temperatures and/or flow conditions for the pollution 
61

control equipment cannot be maintained below approximately 70 percent of nameplate capacity. 

Commenter states that, therefore, pollution control equipment such as the SCR and FGD must be turned 

off while coal continues to be combusted. Commenter states that, as per the manufacturer’s 

specifications the combustion of coal is gradually reduced until the load MW has reached approximately 

5 percent of nameplate capacity before the boiler is completely shut off and produces zero emissions.

Response to Comments 56 - 59: The EPA received a limited number of comments on the definition of 

“shutdown.” Based on those comments and its analysis of startup events, the EPA is maintaining the 

definition of “shutdown” proposed in the November 2012 action and we are continuing the requirement

that all APCDs must be operated as long as coal, residual oil, or solid oil-derived fuel is being burned in 

the EGU, and EGUs must continue to operate the APCDs as long as possible thereafter as feasible, 

considering technological and safety issues. We also believe that, similar to startup, the use of clean 

fuels during shutdown must be maximized to reduce HAP emissions and we have added language to that 

effect. The EPA is also aware of industry practice that involves “buttoning up” the EGU in anticipation 

of a startup in the near future. We understand this to involve ceasing fossil fuel firing and closing 

dampers so that there is no air flow through the system (and, thus, no emissions). However, the 

equipment is maintained such that as little heat as possible is lost (with no additional fuel being fired 

during this period), facilitating a more rapid startup.

1.1.2.1 NSPS

Comment 60: Commenter 5848 agreed that the proposed definition of shutdown is appropriate, but that 

the beginning of shutdown can begin sooner – an unplanned shutdown of steam-using equipment (e.g., a 

turbogenerator or sugar cane grinding mill) can occur and this event can lead to one or more boilers 

immediately venting steam and initiating a shutdown sequence; in such cases, a particular boiler may no 

longer be generating electricity or producing useful thermal energy, but the boiler will begin the process 

of shutting down.. Commenter provides revised language:

Shutdown means the period in which cessation of operation of an EGU is initiated for 

any purpose. Shutdown can begins up to 6 hours prior to when the EGU no longer 

generates electricity or up to 3 hours prior to when the EGU no longer makes useful 

thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling 

purposes or when no coal, liquid oil, syngas, or solid oil-derived fuel is being fired in the 

EGU, whichever is earlier. Shutdown ends when the EGU no longer generates electricity 

or makes useful thermal energy (such as steam or heat) for industrial, commercial, 

heating, or cooling purposes, and no fuel is being fired in the EGU.

Commenter 5848 provides an alternative definition which could apply to all EGUs or be limited to 

biomass-fired EGUs:

Shutdown means the period in which cessation of operation of an EGU is initiated for 

any purpose. Shutdown begins when the EGU no longer generates electricity or makes 

useful thermal energy (such as heat or steam) at the proper pressure, temperature and 

flow rate to a common header system or energy user(s) for use as either process steam, 

for motive power (steam-driven equipment), or for industrial, commercial, heating, or 

cooling purposes or when no coal, liquid oil, syngas, or solid oil-derived fuel is being 
62

fired in the EGU, whichever is earlier. Shutdown ends when the EGU no longer generates 

electricity or makes useful thermal energy (such as steam or heat) for industrial, 

commercial, heating, or cooling purposes, and no fuel is being fired in the EGU.

Response to Comment 60: This comment was submitted to the NSPS docket (EPA-HQ-OAR-2011-

0044) but is similar to comments presented above submitted to the NESHAP docket (EPA-HQ-OAR2009-0234). Therefore, the responses provided to those comments also apply to this one. We would note 

that a biomass-fired boiler that does not meet the definitions in 40 CFR 63.10042 would not be subject 

to 40 CFR Part 63, subpart UUUUU.

1.1.3 Clean fuels

Summary of Comments Received Following November 30, 2012, Proposal

Comment 61: Commenters 20243, 20247, 20269, 20299, and 20302 support the EPA’s inclusion of 

synthetic natural gas and propane as clean fuels that may be used during startup and shutdown.

Commenters 20269, 20279, and 5803 support the EPA’s plan to expand the clean fuels list.

Commenter 20308 agreed with expanding and clarifying the definition of clean fuels used for startup. 

Commenter agreed that the source is required to use one of the listed fuels, but not necessarily the 

cleanest fuel available.

Commenter 20252 supports the inclusion of propane as a clean fuel.

Commenter 20297 supports the EPA’s decision to include ultra-low sulfur diesel (ULSD) as a “clean 

fuel” with negligible emissions that can be used for startup without the need for operation of the ESPs or 

FGD.

Response to Comment 61: The EPA is finalizing an expanded list of clean fuels.

Comment 62: Commenters 20282 and 20295 state that should the definition of clean fuels become final 

as proposed, it is not clear that the use of a distillate oil/biodiesel blend during boiler startup would be 

allowed, which would pose a serious operational challenge to many EGUs. Commenters suggest that the 

EPA should provide greater flexibility in the “clean fuels” definition by adding the language “and other 

clean fuels as approved by the permitting authority.” Commenters suggest that if the EPA is unwilling to 

make that change, the EPA should expand the proposed list of “clean fuels” to include biodiesel and 

other renewable fuels that meet the 40 CFR Part 80, subpart M requirements.

Commenter 20295 suggests that the EPA also should revise the definition to provide that “ULSD, 

NRLM S-15 or equivalent fuels” may be used.

Commenter 5785 supports the EPA’s proposal that ULSD be considered a clean fuel, and states that 

ULSD is the only other fuel on the island of Guam that can be used for startup of the EGUs subject to 

this rule.
63

Commenters 20279, 20304, and 5803 state that biodiesel and renewable fuels should be included in the 

list of clean fuels.

Commenter 20279 notes that two of its facilities are permitted to burn biodiesel in its current Title V 

permits. Commenter notes that including biodiesel would provide EGUs that have fuel constraints with 

important operational flexibility. Commenter observes that some EGUs do not have easy access to 

natural gas, and the proposed change ensures that these plants have additional alternative clean fuels 

from which to choose (syngas, propane, and ULSD in addition to the currently listed natural gas and 

distillate oil).

Commenters 20282 and 5803 state that the EPA must provide greater flexibility in the “clean fuels”

definition by adding the language “and other clean fuels as approved by the permitting authority.”

Commenter 20282 states that several of its members’ coal-fired EGUs fire distillate oil during startup 

and for flame stabilization. Commenter learned that some EGUs who also use distillate oil during startup 

have been informed by their fuel suppliers of their plans to go to a 5-percent (B-5) biodiesel blend 

because of the EPA’s renewable fuel mandate set forth under 40 CFR Part 80, subpart M. Commenter

states that once the current distillate oil inventory depletes, these EGUs will have no other choice but to 

begin to burn a distillate oil/biodiesel blend during startup. Commenter states that it is not clear that the 

use of a distillate oil/biodiesel blend during boiler startup would be allowed under the proposed rule, 

which would pose a serious operational challenge should suppliers no longer provide 100 percent 

distillate oil. 

Comment 63: Commenter 20271 believes the specific listing of ULSD confuses the definition as the 

definition already includes distillate oil. According to commenter, ULSD is a subset of distillate oil and 

by default would be included in the definition. Commenter notes that by specifically listing ULSD as a 

clean fuel, it could be interpreted that the EPA is specifically listing the distillate oils that are acceptable 

clean fuels, making ULSD the only distillate oil acceptable as a clean fuel. Commenter states that it does

not believe that it was the EPA’s intent to limit distillate fuels to only ULSD. To clarify the language, 

Commenter suggests that the EPA list all acceptable grades of distillate oils, or remove ULSD from the 

list of clean fuels in the definition and add language stating “...propane, distillate oils (including, but not 

limited to, ULSD)...”

Response to Comments 62 and 63: The EPA sees no correlation between HAP (including any 

surrogate) emissions and fuels in the requirements of 40 CFR Part 80, subpart M, as this subpart deals 

with renewable fuel standards and greenhouse gas (GHG) emissions which are outside the scope of this 

rulemaking. Thus, the EPA does not believe it appropriate to include renewable fuels subject to the 

requirements of 40 CFR Part 80, subpart M in the definition of “clean fuels.” However, the EPA does 

see merit, as suggested by some commenters, of broadening the definition. After reviewing other rules 

which use or require clean fuels, we believe that inclusion of those fuels meeting the requirements of 40 

CFR Part 80, subpart I (“Subpart I—Motor Vehicle Diesel Fuel; Nonroad, Locomotive, and Marine 

Diesel Fuel; and ECA Marine Fuel”) is appropriate. Specifically, the definitions and provisions of 40 

CFR 80.2, 80.501, 80.510, and 80.520 address sulfur content restrictions relating to distillate, diesel 

(including ULSD), and biomass fuels. The EPA believes that requiring cleaner fuel for EGUs will 

significantly limit or reduce the emissions of regulated air pollutants emitted from these sources, further 

protecting public health and the environment. Information provided to the EPA on another rulemaking 
64

(found in EPA-HQ-OAR-2008-0708-1459)8showed that the use of ULSD will significantly reduce 

emissions of air toxics, including metallic HAP (e.g., nickel, zinc, lead (Pb)). The EPA believes that the 

other 40 CFR Part 80, subpart I, fuels meeting the subject definitions will also significantly reduce 

emissions of air toxics and protect public health and the environment during startup events. The EPA 

has made the appropriate changes to the definition of “clean fuel” in the final rule.

Comment 64: Commenters 20269 and 20279 request that the EPA clarify that when switching from 

higher sulfur distillate to ULSD, EGUs are allowed to use oil already in distillate tanks. Commenter

suggests that the EPA add to the proposed definition of “clean fuel” the following language: “After the 

effective date of the rule, all distillate receipts will be ULSD.” Commenters state that this revision would 

make clear that EGUs may use existing fuel supplies.

Response to Comment 64: The EPA does not believe a change or clarification is necessary. The 

revised definition of “clean fuel” does not require the use of ULSD; all distillate fuel (which includes all 

forms of diesel under the 40 CFR 80.2 definition) meet the definition of “clean fuel.”

Comment 65: Commenter 20276 disagreed with the limitation in the clean fuels definition with the fuel 

options and states that the list should be expanded to include non-fossil fuel options such as biomass 

during periods of startup. Commenter said some coal-fired EGUs implement more traditional methods 

of startup that consist of burning a combination of biomass (i.e., wood chips, wood pallets) and distillate 

fuels. Commenter states that these EGUs do not have the capability of burning gaseous or liquid fuels, 

and would be forced to implement costly retrofits to demonstrate compliance with a work practice 

standard. Commenter urged the EPA to provide greater flexibility and clarifications by expanding the 

list of “Clean Fuels” by recognizing non-fossil fuels (biomass) that meet the 40 CFR Part 63, subpart 

DDDDD, requirements during boiler startups.

Response to Comment 66: The EPA does not have information relating to the HAP emissions resulting 

from biomass in EGUs subject to the MATS rulemaking and, therefore, as opposed to the use of (e.g.) 

ULSD noted above, the EPA is not in a position to say that burning such materials would result in 

sufficiently lower HAP emissions than burning the EGU’s normal fuel during periods of startup. Thus, 

the EPA has not made this change to the definition of “clean fuel.” It appears that commenter also 

indicates that distillate fuels are used and the EPA believes that it is this distillate fuel that is the 

“startup” fuel rather than the biomass (which is simply being used as a substrate); as long as these 

distillate fuels meet the definition of “clean fuel” in the final rule, they would be appropriate for use 

during startup.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 67: Commenter 20397 agreed with expanding and clarifying the definition of clean fuels 

used for startup. Commenter agreed that the source is required to use one of the listed fuels, but not 

necessarily the cleanest fuel available. Commenter supports the revised language in 40 CFR 63.10011.

 

8 Email and attachments from Paul Miller, NESCAUM, to Melanie King, EPA. NESCAUM’s RICE 

NESHAP comments. October 11, 2012 (EPA-HQ-OAR-2008-0708-1459). Also found in docket ID 

EPA-HQ-OAR-2009-0234.
65

Commenter 20426 agrees with and supports the EPA’s proposal to expand and clarify the definition of 

clean fuels used for startup. Specifically, commenter agrees that the source is required to use one of the 

listed fuels, but not necessarily the “cleanest” fuel available. Commenter states that, having the 

flexibility to choose from a menu of options gives utilities flexibility to evaluate local economic 

considerations when selecting a startup fuel such as delivery costs, price and availability as the industry 

plans for MATS compliance activities.

Commenter 20403 supports the expanded list of clean fuels as proposed in the rule for reconsideration 

and continues to support the change.

Commenter 20389 supports addition of other fuels such as synthetic NG, syngas, propane, and ULSD to 

the list of clean fuels used during startup.

Response to Comment 67: The final rule authorizes sources to use any of the clean fuels included in 

the definition during startup and shutdown periods. Moreover, the final rule clarifies clean fuel 

monitoring, reporting, and recordkeeping requirements, in conjunction with clarifying startup 

monitoring, reporting, and recordkeeping requirements (see 40 CFR 63.10020(e)(1) and (2)).

Comment 68: Commenter 20400 states that the EPA’s November 2012 proposed revisions to 40 CFR 

63.10011(f) appropriately provide greater flexibility for a source to choose among available clean fuels. 

Commenter states however, in addition to the fuels in the expanded list, biodiesel should be allowed as a 

fuel for startup and shutdown. Commenter states that biodiesel is a regulated fuel product subject to 

ASTM specifications for pure product and in various blends with No. 2 distillate fuels. Commenter 

states that biodiesel may be blended with fuel, including ULSD, at up to 5 percent blend with no 

required disclosure to the purchaser.

Commenter 20400 states that the proposed revisions also include a new definition for the term “clean 

fuel” in 40 CFR 63.10042. Commenter states that biodiesel fuel should also be added to that definition. 

Commenter states that in addition, the term “distillate oil” in 63.10042 needs to be revised to be 

consistent with the fuels allowed under the definition of “clean fuels.” Commenter states that as 

currently defined, distillate oil refers only to heating oil defined as ASTM D396-10. Heating oil and 

diesel fuel are essentially interchangeable for use in boilers and combustion turbines (CT), and the 

product delivered will depend largely on the local fuel market (which in many areas is dominated by the 

transportation sector and diesel fuel). Commenter recommends that the subpart UUUUU definitions 

should adopt the same definition as found in 40 CFR 60.41b and 60.41c (which were added to the NSPS 

rules in the same February 16, 2012, Federal Register notice that published the subpart UUUUU MATS 

rule): 

Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply 

with the specifications for fuel oil numbers 1 and 2, as defined by the American Society 

of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17), diesel 

fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in 

ASTM D975 (incorporated by reference, see § 60.17), kerosene, as defined by the 

American Society of Testing and Materials in ASTM D3699 (incorporated by reference, 

see § 60.17), biodiesel as defined by the American Society of Testing and Materials in 

ASTM D6751 (incorporated by reference, see § 60.17), or biodiesel blends as defined by 
66

the American Society of Testing and Materials in ASTM D7467 (incorporated by 

reference, see § 60.17).

Response to Comment 68: As noted above, the EPA does see merit of broadening the definition to 

include those fuels meeting the requirements of 40 CFR Part 80, subpart I. Specifically, the definitions 

and provisions of 40 CFR 80.2, 80.501, 80.510, and 80.520 address sulfur content restrictions relating to 

distillate, diesel (including ULSD), and biomass fuels. The EPA believes that requiring cleaner fuel for 

EGUs will significantly limit or reduce the emissions of regulated HAP emitted from these sources

during startup and shutdown periods, further protecting public health and the environment. We do not 

believe a further expansion of the available clean fuels is warranted or necessary at this time. 

Comment 69: Commenter 20415 supports defining clean fuels in the MATS rule to include biodiesel 

and other renewable fuels, as well as the additional clean fuels noted above that EPA has identified in 

the final subpart DDDDD rule. Commenter states that biodiesel and other renewable fuels that meet the 

EPA renewable fuels standards are by those rules considered equivalent to conventional commercial 

fuels and similar or preferred in nature to fossil based fuels. Commenter states that to the extent EGUs 

utilize those renewable fuels for SS purposes, the rule should allow their use as “clean fuels.”

Commenter states that in addition, as the EPA is advancing biofuel production through the 40 CFR 80, 

subpart M, rules, it is logical that those fuels also be allowed as startup fuels in this rule.

Commenters 20417 and 20419 agree that the clean fuels list should be expanded. Commenter 20417 

believes that the list should include other clean fuels, such as biodiesel and other renewable fuels. 

Commenter 20419 suggests the list should also include biofuels and refinery gas. Commenters state 

expanding the list of clean fuels will increase regulatory flexibility without major impacts to the 

environment.

Commenter 20402 supports the EGU industry commenters that advocated that the EPA should expand 

its proposed list of “clean fuels” to include biodiesel and other renewable fuels that meet the 40 CFR 

Part 80, subpart M, requirements. Commenter states that, at a minimum, the EPA should expand the 

definition of “clean fuels” in the MATS rule to mirror that in the final Boiler MACT rule, which 

includes “natural gas, synthetic natural gas, propane, distillate oil, syngas, ultra-low sulfur diesel, fuel 

oil-soaked rags, kerosene, hydrogen, paper, cardboard, refinery gas, and liquefied petroleum gas” and 

notes that this list is broader than the one included in the MATS rule. However, commenter maintains 

that this list is still not reflective of all the fuels that are fired during startup, and the EPA should take 

another look at how units utilize fuels during startup; many EGU units need to co-fire “clean fuels” with 

the primary fossil fuel at some point during the startup process in order to make the necessary transition 

to full operations using the primary fuels.

Commenter 20416 states that the definition of “Clean Fuels,” which must be used under the MAT’s 

startup and shutdown work practice standards should be further expanded. Commenter states that the 

EPA proposed several modifications to finalize the “clean fuels” work practice standards including the 

addition of synthetic natural gas (NG), syngas, propane, and ULSD. Commenter states that, however, 

the EPA has failed to consider the use of non-fossil fuel sources such as wood scrap as a “clean fuel” in 

order to further expand its list of “clean fuels” within the June 25, 2013, reopening of the public 

comment period. Commenter states that, as provided in its comments filed on January 7, 2013, many 

older coal-fired EGUs implement more traditional methods of startup which consists of burning a
67

combination of biomass or bio-based solid fuel (i.e., wood chips, wood pallets, scrap wood products) 

and distillate fuels.

Commenter 20416 states that the EPA has not provided adequate guidance for those EGU’s which 

incorporate more traditional methods of startup consisting of burning bio-based solid fuels (scrap wood 

products) and distillate fuels. Commenter states that if EGU’s are required to startup while burning 

gaseous or liquid fuels only, EGUs will be forced to implement costly retrofits and potentially require 

the establishment of firm natural gas delivery contracts to demonstrate compliance with the work 

practice standards that applies for only short and limited durations annually.

Commenter 20416 urges the EPA to provide greater flexibility and clarifications by expanding the 

definition of “clean fuels” by recognizing non-fossil fuels such as wood products, to be combusted 

during boiler startups in a manner consistent with the Biomass or bio-based solid fuel definition found in 

40 CFR Part 63, subpart DDDDD.

Response to Comment 69: The EPA does not have information relating to the HAP emissions resulting 

from biomass or other materials identified in the final 40 CFR Part 63, subpart DDDDD, rule in EGUs 

subject to the MATS rulemaking and, therefore, as opposed to the use of (e.g.) ULSD noted above, is 

not in a position to say that burning such materials would result in sufficiently lower emissions than 

burning the EGU’s normal fuel during periods of startup. Thus, the EPA has not made these changes to 

the definition of “clean fuel.” Commenters note that distillate oil is used in the “traditional methods” of 

startup and the EPA believes that it is this distillate fuel that is the “startup” fuel rather than the biomass 

(which is simply being used as a substrate); as long as these distillate fuels meet the definition of “clean 

fuel” in the final rule, they would be appropriate for use during startup.

Comment 70: Commenter 20421 supports the expansion of clean fuels definition to include propane 

distillate oil and ULSD because it accounts for the design limitations to certain startup fuels of some 

boilers.

Response to Comment 70: The EPA is finalizing an expanded list of clean fuels that includes the 

identified fuels. 

1.2 Work Practices

Summary of Comments Received Following November 30, 2012, Proposal

1.2.1 General Support

Comment 71: Commenters 20252, 20271, 20281, 20288, 20295, 20302, and 20304 support the use of 

work practice standards during periods of startup and shutdown. Commenter’s reasons for its support 

included the EPA’s lack of data to establish emission limits for startup and shutdown and because it is 

not feasible to conduct valid tests during startup and shutdown periods.

Response to Comment 71: These comments require no response.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period
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Comment 72: Commenter 5834 asks that the bright line test for defining the end of startup also be 

applied to the work practice standards that apply to coal-fired EGUs during the startup period.

Comment 73: Commenters 20389, 20401, and 20424 support work practice standards in lieu of numeric 

standards for startup.

Commenter 20393 generally supports the proposed refinements to the work practices but still has 

concerns regarding the application of the startup work practice requirement to ESPs installed at coalfired EGUs for limiting filterable PM emissions. Commenter notes that the use of work practice 

standards in lieu of numeric emissions limits is justified for several important reasons: (1) emissions 

during startup and shutdown are not representative of normal operation because the ESPs and other 

APCDs are either not operating or operating at low removal efficiency levels because the APCDs are 

operating far from their design conditions; the MATS limits were calculated based on the EGUs 

operating full load with all pollution control equipment running at maximum control efficiencies and 

therefore failed to account for the variation of much higher emissions during startup and shutdown 

periods; the EPA did not have the necessary data to set numeric standards during startup and shutdown 

given that it is not feasible to monitoring emissions due to the transient nature of these periods.

Response to Comments 72 and 73: Commenter’s assertion that the numeric standards only account for 

emissions during maximum control efficiency fails to acknowledge that the EPA applied a variability 

factor to the HAP emissions data when establishing the MACT floors and those floors represent a level 

that can be achieved at all times, including during low load periods and the defined startup and 

shutdown periods. The EPA also provided additional variability through application of the 30-day 

rolling average to further offset any spikes in emissions for sources demonstrating compliance using 

continuous emissions monitoring systems to account for variability in emissions during non-peak 

periods. The EPA had initially proposed to apply the numerical standard during startup and shutdown 

periods believing that the variability included when setting the standards was sufficient to address those 

emissions, and no commenter has provided any information or data that legitimately call that conclusion 

into question. The EPA never indicated that it needed to include a work practice for startup and 

shutdown periods because we believed the numerical standards could not be achieved if the startup and 

shutdown emissions were included in the 30-day average (the EPA successfully defended all challenges 

to MATS, including the existing source MATS limits, in White Stallion Energy Center v. EPA. 748 F.3d 

1222 (D.C. Cir. 2014)).

Commenter’s concerns about the efficiency of controls directly after startup is not supported in the 

record. As explained above, we do not have HAP emissions data from those periods. However, we do 

have an analysis of NOX and SO2 emissions and that analysis shows a quick decline in those emissions

immediately after controls are engaged at EGUs. This fact suggests commenters’ concerns are 

misplaced, and, as we said above, sources can combust clean fuels alone without generating electricity 

for a longer period of time to warm up the system and continue to maximize those clean fuels to offset 

any inefficiency that may occur at individual EGUs after the end of startup.

Finally, commenter asserts, without data, that HAP emissions are always higher during startup and 

shutdown periods such that it would not be possible to comply with the 30-day rolling average if startup 

and shutdown periods were included. We do not agree with this assertion, particularly for the best 
69

performing EGUs upon which the standard is based. For those EGUs, we believe it likely that their HAP 

emissions are actually lower during those periods, even before fully complying with the final work 

practice. We believe that had the EPA determined not to establish a work practice standard during these 

periods, sources that were concerned about compliance with the 30-day rolling average would have 

employed some of the work practice requirements or made other modifications to the EGUs to ensure 

compliance with a 30-day rolling average that included the defined startup and shutdown periods. But,

we continue to note that we do not have HAP data during startup and shutdown periods and the testing 

methodologies are not currently certified to accurately measure at these times. For these reasons, any 

assertions that the February 2012 final MATS standards do not include sufficient variability to account 

for HAP emissions during startup and shutdown are without foundation, and the information we have 

leads us to conclude that the best performing EGUs would have HAP emissions during startup and 

shutdown periods that are as low or lower than HAP emissions during periods other than startup and 

shutdown such that compliance with the 30-day rolling average would not be a problem.

Comment 74: Commenter 20389 states that CEMS are designed to collect and measure pollutants in 

very narrow (flue) gas concentration ranges under stable operating conditions. Commenter states

unsteady conditions during startup interfere with CEMS ability to accurately sample and measure 

pollutants, data from CEMS under unsteady conditions are known not to be representative, and CEMS 

provided out-of-range values.

Response to Comment 74: The EPA believes the commenter’s concerns are misplaced, because the 

monitoring information during startup or shutdown periods is to be collected, recorded, and reported, but 

not used for compliance purposes, so the magnitude of CEMS values during those periods do not affect 

compliance. However, collection of this monitoring information during these periods may provide 

insights on EGU and CEMS operation and performance, which could lead to additional rulemaking in 

the future. Without the data, the EPA will remain in a perpetual state of ignorance concerning these and 

other characteristics during startup or shutdown periods. Consistent with the final rule, no numeric 

standard applies during startup or shutdown periods, as defined. Moreover, as mentioned below, 

emissions during startup or shutdown periods are expected to be minimized due to the short duration of 

the period, the application of PM emissions controls within 1 hour of primary fuel combustion, and the 

combustion of clean fuels. Furthermore, as explained below, use of diluent caps and/or minimum 

electrical production is expected to mitigate out-of-range CEMS values for sources that share a common 

stack.

Comment 75: Commenter 20420 states that the revisions to the APCD operation provisions of the 

startup and shutdown work practice standards proposed as part of the new source MATS reconsideration 

on November 30, 2012, should be finalized.

Commenters 20390, 20414, and 20430 support the work practice standard during startup and shutdown 

assuming the SS periods are appropriately defined. 

Commenter 20403 supports the proposed revisions to Table 3 of subpart UUUUU of Part 63. 

Commenter states that the EPA correctly acknowledged that it takes a sequence of steps that involve 

achieving certain temperatures, sequencing the introduction of coal refuse and limestone to bring the bed 

temperature up to level where the bed is stable; and the timing of addressing NOx controls or other 

APCDs to be engaged.
70

Comment 76: Commenter 20400 believes it is appropriate that the EPA did not establish numerical 

emission limits during startup and shutdown periods because it lacked the necessary data to do so. 

Commenter states that assuming that the EPA expands the definition of a startup, any operations during 

that period would continue to be subject to the work practice standards.

Response to Comments 75 and 76: These comments require no response.

1.2.2 Not Support Further Changes

Comment 77: Commenters 20422, 20427, 20436, and 20438 opposed changes to startup.

Commenter 20422 opposed any changes in the startup definition and opposed exempting EGUs from 

numeric limits at any point after electricity is generated. Commenter did not believe industry or the EPA

has established either a legal rationale or factual basis for these changes. Commenter states any further 

rollbacks will undermine this regulation, reduce its benefits, and create confusion within the regulated 

community and state agencies. 

Commenter 20427 opposed weakening of the startup work practice standards. Commenter states the 

EPA should not and cannot lawfully extend the work practice standard to a greater portion of coal-fired 

EGU operations. Commenter states readily available APCDs allow compliance with the standards as 

finalized. Commenter states an expanded exemption would diverge from the statutory mandate to 

provide work practices equivalent to the maximum achievable pollution reductions. Commenter states

the fundamental obligation imposed by the CAA’s air toxics provision is to spur the installation of stateof-the-art APCD technologies.

Commenter 20427 states that startup and shutdown events have historically caused disproportionate and 

enormous pollution (noted in a February 2013 memorandum regarding State implementation plans, 

SIPs). Commenter states that an expanded exemption for startup and shutdown would vitiate much of 

the rule’s benefit; it would allow older EGUs with outdated APCD to avoid upgrading those controls 

(provides a summary showing SSM emissions that range from 11 to 300 tons per year PM, for 2011 

from EGUs in Texas). Commenter states that the resulting harm would be concentrated on vulnerable 

communities working and residing in close proximity to older, less efficient plants.

Commenter 20422 states the EPA has already conceded that uncontrolled emissions of HAP during 

startup can pose significant risks to human health, and the EPA will have to explain how expanding the 

startup exemption affects these risks.

Commenter 20427 cites the EPA’s data of 9,719 startup events in 2011 and 2012, with 9 to 10 startups 

per year on average, and a small number of older EGUs experienced over 100 startup events in 2011 and 

83 in 2012. Based on the EPA’s data, commenter states the current proposed rule would exempt 9 hours 

of fossil-fuel combustion for each start (or 43,736 hours of coal and oil-fired operation per year) (9,719 

starts divided by 2, times 9 hours), and expanding the definition by another 6 hours would exempt 

another 27,157 hours (9,719 starts divided by 2, times 6 hours). Commenter states pollution would be 

highest at older, sub-critical EGUs with large numbers of startup events, and these older EGUs are 

generally located in urban areas, densely populated by poor and minority populations.
71

Commenter 20427 states that as coal-fired EGUs are forced to load-following or intermittent use by gasfired EGUs and renewables, the number of startups for coal-fired EGUs has increased. Commenter notes

that more than half of the nation’s coal-fired EGUs operated at less than 70 percent capacity factor in 

2012, suggesting a move toward intermittent operations and frequent startups (provides an attachment to 

its comment letter, showing capacity/utilization factor for coal-fired EGUs reporting under the Acid 

Rain Program).

Commenter 20427 notes that recent studies indicate that the EPA estimates of Hg health impacts may be 

underestimated, and underscores the importance of setting stringent standards, including during startup 

and shutdown. Commenter cites recent studies that found some individuals might be more genetically 

predisposed to negative effects of Hg exposure than others, and notes a study that found approximately 

10 percent of the more than 1,000 children studied had mutations in their genes that possibly contributed 

to a steeper decline in IQ from exposure to Hg compared to others without the mutation. In another 

study, commenter notes that very high concentrations of methyl Hg were found in rice gown in farms 

contaminated by Hg released from mining activities, further notes that these studies question the 

assumption that most methyl Hg exposure (the neurotoxic organic form of Hg that accumulates in food 

chains) comes from consuming fish. Commenter states the science on interaction between climate 

change and Hg pollution is evolving; climate change will worsen Hg pollution by increasing inorganic 

Hg deposition on waters, methyl Hg production, and methyl Hg bioaccumulation in the food chain over 

the next few decades.

Commenter 20436 notes that the final rule required that APCD be fully operative before coal 

combustion begins and that it does not believe any weakening of these requirements is warranted or 

lawful when the pollution control requirements are the methods used to assure compliance with the 

standards that must apply continuously. Commenter states that many power plants have already installed 

fabric filters and alleges that many others will do so soon. Commenter maintains that when properly 

sized, these filters can effectively control PM as soon as coal combustion begins.

Commenter 20438 states that startup periods are not necessarily brief or infrequent – as coal-fired

EGUs have been forced into intermediate-cycling roles by cheaper natural gas EGUs, coal-fired EGUs 

are starting up and shutting down with increased frequency and older, less efficient EGUs (typically 

with older controls, and thus very high startup and shutdown-related emissions) experience the largest 

number of re-starts. Commenter alleges that, although less rigorous than the numeric standard in the 

proposed rule, the work practice standard in the final MATS rule, if it is rigorously enforced, should 

directly and effectively solve the central concern associated with startup and shutdown: uncontrolled 

coal combustion. Commenter maintains that the EPA is conducting reconsideration proceedings that 

could drastically weaken the MATS’ work practice standard. Commenter states that there is no reason 

for such weakening and that the standard is eminently achievable. Commenter alleges that the MATS’ 

work practice would require EGUs that currently do not operate their PM APCDs during periods of 

startup to update their pollution controls, reducing their PM pollution by as much as 20 percent per year. 

Commenter further alleges that certain EGUs in Texas currently refuse to operate pollution-controls, 

even when generating power; they produce, at times, over 300 MW per hour for several hours before 

activating PM controls. Commenter maintains that producing this much electricity without any 

operational PM controls leads to very high pollution levels and that the work practice, if implemented 

and enforced faithfully, would effectively end that pollution.
72

Commenter 20438 states that legally and practically, there are no grounds to weaken the work practice 

standard included in the final MATS and as an administrative matter, the work practice standard could –

if retained – provide the EPA with a very straightforward means of ending uncontrolled pollution during 

startup and shutdown. Commenter maintains that the increasingly tangled state implementation plan 

provisions governing startup and shutdown demand substantial EPA oversight resources to accomplish 

their desired effect. Commenter alleges that the work practice should directly achieve the same end –

ensuring that pollution controls are used during routine startup and shutdowns – for one large source 

category, by directly requiring such operation.

Response to Comment 77: The EPA maintains that the alternative definition of startup included in the 

final rule is appropriate considering the available information. In the original MATS proposal, the EPA 

proposed to apply the numerical standards at all times, including periods of startup and shutdown, but 

we finalized a work practice in response to comments and consistent with our understanding of the EGU 

startup and shutdown processes at the time. The petitions for reconsideration provided some additional 

information, though it was not until the first comment period that the EPA obtained information that 

caused us to conclude that the work practice we finalized may not fully account for the performance 

variability of the best performing EGUs during periods of startup and shutdown, or fully address the 

monitoring issues associated with startup and shutdown periods. In addition, the EPA during the initial 

comment period developed the analysis included in the Startup TSD, and the Agency provided an 

additional opportunity for comment on the analysis in that TSD. The EPA subsequently revised the 

Startup TSD in response to comments and developed the Revised TSD included in the docket for this 

final action. Based on all of this information, the EPA decided to provide an alternative definition for the 

end of startup that we maintain represents the average performance of the best performing 12 percent of 

EGUs, consistent with CAA sections 112(d) and (h).

Some commenters state that all EGUs can get all of their APCDs on line at the time electricity 

generation begins, but the data do not support that conclusion. While the record indicates that some 

sources are able to engage all APCDs at the same time as the start of generation, the record does not 

support a conclusion that such ability is widespread. Conversely, the record as demonstrated in the 

Revised TSD does support a conclusion that the best performing EGUs on average engage all APCDs 

within 4 hours of electricity generation. The requirements to maximize clean fuel use and to engage the 

PM control within 1 hour of combusting coal represent what the best performing EGUs are doing during 

startup, consistent with CAA sections 112(h) and (d). In any case, these commenters do not address the 

EPA’s concern with HAP measurement accuracy during the defined startup period. 

Commenters also maintain that the proposed changes to the final work practice undermine the rule for 

various reasons and weaken and/or remove the benefits of the final rule. It appears that these

commenters are asserting that the work practice in the final rule was sufficiently stringent to ensure that 

the HAP emissions during startup and shutdown would be at or below the numerical limit applicable 

during all other periods, but that the proposed revisions make the work practice less stringent than the 

numerical limits. But that is not the statutory test for a work practice and there are no HAP data from the 

periods of startup and shutdown as we have defined them in this final rule. It is the lack of data and the 

fact that the EPA does not currently have HAP measurement methodologies that are certified to monitor 

emissions during those periods that caused the Agency to establish a work practice for startup and 

shutdown period.
73

Furthermore, based on the information provided to the EPA and our own analysis, the Agency believes

that the final rule establishes a work practice that is consistent with the statute and protective of human 

health and the environment. We do not disagree that the work practice contained in the February 2012 

final MATS rule is likely more stringent than the alternative provided in this final action on 

reconsideration, but that fact does not negate the validity of the alternative in light of the facts and the

statutory requirements as discussed elsewhere. In addition, we believe that under either alternative the 

level of HAP emissions during the defined startup period may in fact be less than the HAP emissions 

during all other periods when the numerical limits apply because of the requirement to maximize the use 

of clean fuels for what at times may be an extended period; prior to this work practice sources would be 

able to co-fire coal, solid oil-derived fuel, or residual oil with minimal clean fuel almost immediately

after initial fuel combustion absent the work practice, and our ability to accurately monitor emissions 

during those periods does not exist. The requirement to continue to maximize clean fuel use throughout 

the startup period and to engage and operate the PM control within 1 hour of adding coal, residual oil, or 

solid oil-derived fuel to the EGU also ensure that HAP emissions will be reduced during startup. Neither 

of these requirements would exist if sources were required to comply with the numerical limits during 

startup and shutdown, though sources may have employed such approaches to ensure compliance with 

the numerical limits if they applied during startup and shutdown and the HAP emissions could be 

accurately measured during those periods. Finally, the work practice is currently practically enforceable 

during periods of startup and shutdown because it relies on information that can be effectively obtained 

and reviewed without HAP emissions data. We question the ability to practically enforce the numerical 

limits during periods of startup and shutdown given the legitimate concerns with our current ability to 

effectively capture and accurately measure HAP emissions during the defined startup and shutdown 

periods.

Comment 78: Commenter 20436 states that should the EPA propose to relax the standard, then, at a 

minimum, it should require that EGUs:

• disclose the methods used to calculate and report emissions when APCD are not fully 

effective, and to include such emissions when determining compliance with the 30-day 

rolling averages. Such disclosure should include a full explanation of any “drop-out” 

factors that are alleged to reduce PM emissions during SS, and an estimate as to how 

much of these particulates are later released to the atmosphere during maintenance or 

normal operations;

• certify that APCD is designed to accommodate the maximum flow of gas from the 

boilers it serves, and is suitable for the type of fuel used for combustion; and

• disclose the temperature and flow rate required for full operation of APCD, based on a 

certification from the designer or vendor of such equipment.

Response to Comment 78: The EPA has revised the final definition of “startup” for the reasons 

discussed in this RTC and the preamble to the final rule. Given the additional information the rule now 

requires for EGUs that choose not to use CEMS for compliance purposes (e.g., hourly flow and 

temperature data, fuel use, and control device parameter measurements), the EPA finds the specific 

disclosures and certifications suggested by the commenter to be unnecessary.
74

1.2.3 Standard Already Accounts for Variability

Comment 79: Commenters 20422 and 20427 state the emission limits already account for startup.

Commenter 20422 indicates the emission limits were designed to accommodate emissions during startup 

periods. Commenter states that emission limits for Hg, non-mercury metals, and acid gases were 

established through a four-step process and notes that the EPA first identified the limits already achieved 

in practice by the best performing EGUs, based on an extensive review of multiple stack tests from 

EGUs representing at least 12 percent of the industry. Because stack test results measure performance 

over a 3- to 4-hour time period, commenter indicates that the EPA then inflated those results – by more 

than a factor of 10 for non-mercury metals – to account for any operational variability that might affect 

emissions. Commenter states that this adjustment was designed to ensure that the best performers could 

meet these standards on a short term basis (equivalent to the several hours needed to complete a stack 

test) at least 99 percent of the time. Commenter alleges that the EPA then further relaxed the standard by 

allowing EGUs to determine compliance based on a 30-day rolling average, rather than the much shorter 

time periods used in stack testing and then, finally, EGUs were exempt from these limits during the 

startup period between boiler ignition and electricity generation or heat transfer, but required the use of 

clean fuels (natural gas, distillate, or ULSD) until startup ended.

Commenter 20422 states the EPA never fully explained why it lengthened the averaging period to 30 

days, but the record shows the EPA intended the longer averaging time to address any short-term 

emission spikes associated with startup or shutdown (citing 76 FR 25044-45). Commenter states the 

EPA must explain why a 30-day rolling average is still needed if EGUs are not required to comply for 

much longer periods after power is first generated. Commenter states if the EPA decides to extend the 

startup exemption, there is no real justification for such a long-term average, especially after the EPA

has already determined the best performers can meet limits over a much shorter time period at least 99 

percent of the time. Commenter states that because emission limits shrink when exemptions are 

expanded, the EPA cannot consider one without reopening the other.

Commenter 20422 states industry comments do not establish that emission limits cannot be met over the 

30-day averaging period. Commenter states that most industry comments provide no data to evaluate the 

vague concerns cited, and broad statements or expressions of concern with no supporting evidence 

should not be enough to reopen a standard that the EPA finalized more than 18 months ago. Commenter 

states that compliance is based on a 30-day rolling average, and emission spikes that may occur a few 

hours after power is generated are averaged out by the lower emissions that occur over long periods of 

normal operation when APCDs are fully engaged. Commenter states industry comments provide no 

actual data to show the impact and only state that some plants “might” have a problem complying. 

Commenter states this is the third opportunity that the EPA has given industry to document why startup 

over a few hours makes it impossible to meet the emission limits averaged over 30 days. Commenter 

further notes that CEMS data are available (for SO2); one industry expert testified that stack testing is 

possible during startups as long as flow rates are relatively stable during the test period; data reported to 

CAMD show that flow rates (and heat rates, a proxy for flow rates) can remain relatively stable for 

several hours over startup, providing sufficient opportunity to complete stack tests, and it is unclear why 

industry comments chose not to conduct emissions testing during startup (citing to expert testimony

provided by industry). Commenter states the EPA identified specific technologies or work practices that 

could be used to limit emissions until APCDs become fully operational but industry commenters have 
75

not explained why none of these options are workable to meet the standards. Commenter states neither 

the EPA nor industry commenters have provided enough data to show that unless startup exemption is 

widened, it will be impossible to comply with pollutant or surrogate limits.

Commenter 20433 rebutted that the UPLs can only predict the 99th percentile of the data actually 

represented by the distribution used to determine those UPLs. Commenter notes that the EPA’s ICR 

database contained no startup emissions data, as testing was conducted at full load as required by the 

EPA. Thus, commenter alleges that the EPA’s UPL analysis does not account for emissions variability 

during startup events, as during startup events, not all pollution control equipment can be operated in 

accordance with manufacturer specifications and an owner/operator thus could not have certified such 

data. Commenter believes that Commenter 20422’s assertion that EGUs can meet the standards “at least 

99% of the time” – if startup events are included – is unsubstantiated.

Commenter 20433 further indicates that industry has submitted data showing how EGUs would not be 

able to meet 30-day emission limits if startup emissions were included (e.g., Attachments 3 and 4 to 

EPA-HQ-OAR-2009-0234-17775 contain detailed analysis of several sets of PM CEMS data). 

Commenter 20433 alleges that the PM data from Cross Unit 1 is especially pertinent to the assertion by 

Commenter 20422, noting that Cross Unit 1 endured a difficult startup in April 2010, and its 30-day 

emissions average would have exceeded the 0.030 lb/106 Btu PM MATS limit as a result.

Commenter 20433 states that it does not dispute that data could be collected using stack tests during

startup and shutdown but maintains that the data collected would not be accurate. In the deposition 

testimony cited by Commenter 20422, it was never said that accurate stack testing was possible during 

startup, noting that Method 5 (a method used to measure PM emissions) “[i]s designed to test the steady 

state conditions.” (emphasis added). Commenter 20433 notes that, as explained in the testimony, the key 

to running an accurate Method 5 test is to have stable flow rates during the performance of the manual 

test run and that stable or volumetric flow is not present during the startup of an EGU because EGU

startup is characterized by rapidly increasing fuel and air flows. Method 5 requires that sampling be 

performed isokinetically, which means that the sampling rate must be matched to a constant flue gas 

velocity. Commenter 20433 maintains that although Commenter 20422 claims that there are data to 

support its assertion that “flow rates can remain relatively steady,” Commenter 20422 provides no such 

data for review; instead, Commenter 20422 provide limited heat rate data showing that the heat rate at 

Duke Energy’s Wm. H. Zimmer plant reported a relatively consistent heat rate for a 3-hour window 

during one startup event. Commenter 20433 alleges that Commenter 20422 provides no support for its

assertion that “[h]eat input can generally be used as a proxy for flow rates.” Commenter 20433 states 

that although Commenter 20422 cites one very short time period in its comments, simply looking at the 

periods immediately before and afterwards shows that the analysis fails completely and maintains that 

even if such a general relationship were established, the existence of a general correlation between flow 

rate and heat input does not mean that the flow rate is stable enough to conduct stack tests whenever 

heat input is relatively stable (a precisely stable flow rate is the relevant parameter in assuring stack test 

accuracy).

Commenter 20422 states that a handful of EGUs emit significant PM during (SSM) events whereas most 

EGUs emit less than 10 ton PM during these events (provides an attachment to its comment letter, a 

summary showing SSM emissions that range from 0.0 to 310 tons per year TSP, for 2011 from coal- and 

oil-fired EGUs in Texas). Commenter states an expanded exemption for startup would allow easier 
76

compliance for the worst-performing facilities but have no effect on most EGUs in Texas to meet the 

limits. Commenter states plants that report large PM emissions during SSM events release only a few 

pounds of individual HAP such as arsenic (As) and Pb and most plants report no HAP releases during 

SSM events.

Commenter 20436 states that permits issued in Texas in 2011 for 10 plants (20 EGUs) authorize PM 

emissions during SSM periods up to 7,616 pounds per hour, far higher than allowable during “normal” 

operations. Commenter notes that these permits do not restrict the number of SSM events or hours 

during which these higher limits apply but alleges that if the allowable limits are reached for just 80 

hours per year (about 1 percent of operating time), SSM emissions would account for between 15 and 66 

percent of annual emissions the remainder of the year at these plants (based on 2012 emission inventory 

data). Commenter maintains that exempting these emission spikes would not only be unlawful but 

would leave the public exposed to higher levels of the hazardous metal that are associated with PM and 

would significantly undermine what the EPA has accomplished with the MATS rule.

Commenter 20433 alleges that the data contained in Attachment A to Commenter 20422’s comments do 

not advance its assertion that industry would not have difficulty meeting the limits. Commenter 20433 

notes that first, the data provided are only for total suspended particulates, which is not a HAP and not 

used as a surrogate under the MATS rule and moreover, the data are provided on a ton/year basis, with 

no information about what the emission rates are for the averaging periods relevant in determining 

compliance with MATS limits.

Commenter 20422 states industry’s request to develop “plans” that would be “reviewed” by state 

agencies is based on the “general duty” provisions of CAA section 112, which the D.C. Circuit has 

already held is not sufficient rationale for substituting work practice standards for emission limits (cited 

Sierra Club v. EPA). Commenter states many states lack capacity or inclination to “review” SS plans 

and generally accept whatever the regulated industry defines as a “plan.” Commenter states allowing 

regulated industries to decide when emission limits apply and when they do not invites the fox to guard 

the henhouse and does not square with a statute that requires emission limits be met at all times. 

Commenter provides an example where a state-approved PM and Pb emissions at rates 10 times higher 

than the allowable emissions limits that apply during normal operation for up to 900 hours per year. 

Although one industry commenter proposed startup not end until 4 hours after generation has reached 25 

percent capacity, commenter states that the industry commenter has not demonstrated that any extension 

is needed to assure compliance with limits based on 30-day rolling averages.

Commenter 20427 states that the EPA’s reconsideration notice cites, as its impetus, concern that a 

limited number of coal-fired EGUs may not be able to operate their current pollution controls at low 

temperatures. Commenter maintains that those claimed temperature constraints do not justify further 

exemptions from the MATS’ numeric limits, that the EPA has vastly inflated the standards in the name 

of “variability,” including – expressly – variability resulting from operations at lower loads, and that the 

EPA has further provided “additional allowance of variability” by expanding the averaging period to 30 

days.

Commenter 20427 states the standards already allow easy compliance at all times, including periods of 

low load following startup, because the EPA inflated the standards to account for variability, including 

variability resulting from lower loads, and the EPA further provided for variability with an averaging 
77

period of 30 days. Commenter notes that the PM standard is generous at 0.03 lb/MMBtu, averaged over 

30 boiler-operating days, and allows 4 to 5 hours with PM emissions at 10 to 100 times that level over 

any 30-day period, which is adequate to accommodate any startup related concerns (commenter provides

a spreadsheet simulating PM emissions and 30-day averaging period emission values). Commenter 

further notes that both ESPs and baghouses for PM may be operated during startup and shutdown to 

lower these values and that SO2 rates have only minor variations during startup. Commenter alleges that 

readily available pollution control methods permit compliance with the MATS’ numeric limits whenever 

electricity is being generated (indeed, whenever coal is being burned at an EGU); industry may be 

reluctant to invest in those methods, but that provides no grounds to exempt EGUs from compliance. 

Commenter maintains that the primary purpose of the CAA’s air toxics provisions is to compel that 

investment, and the resulting protection of public health.

Comment 80: Commenter 20436 states that it does not believe that the EPA will be able to show that 

EGUs operating above the MATS floor cannot comply with the filterable PM limit of 0.03 lb/MMBtu 

based on a 30-day rolling average or that the EPA could make this determination without reviewing and 

perhaps revising the methodology used to determine the floor. Commenter alleges that, according to the 

Energy Information Administration, 70 percent of existing power plants have already installed APCD 

needed to comply with the MATS limits.

Commenter 20427 states that readily available APCD allow compliance with the numeric limits when 

electricity is being generated, and when coal is being burned at an EGU. Commenter states that industry 

may be reluctant to invest in those APCD methods but this provides no grounds to exempt EGUs from 

compliance. Commenter states the primary purpose of the air toxic’s program is to compel investment, 

and the resulting protection of public health.

Comment 81: Commenters 20422 and 20436 state the EPA may not expand the startup definition 

without reopening the emission limits and averaging periods of the rule. Commenters state redefining 

startup definition amounts to a constructive reopening of the numeric emission limits. Commenters state

the numeric limit and averaging period were explicitly crafted, according to the EPA, to reflect 

variability experienced by the best-performing plants, including low load and startup operations, and the 

EPA cannot now exempt those operations without providing more stringent limits that reflect the lesser 

variability in emissions when those operations are excluded. Commenters state the data does not 

illustrate how emission spikes during a few hours of startup affect compliance with limits based on 30-

day rolling averages. Commenter 20436 states that the final rule required EGUs to meet the 30-day limit 

whenever coal was burned to generate electricity and alleges that the EPA cannot exempt periods of coal 

combustion without reopening the emission limit and the 30-day averaging period.

Commenter 20436 alleges that reopening the rule through expanding the startup definition may also 

require re-evaluating the multi-EGU averaging option because the emission rate for multi-EGU 

averaging is calculated by dividing the total mass (pounds per hour) by the total heat input for each 

covered EGU within the 30-day averaging period. Commenter maintains that individual EGUs not 

covered by this average add up the emission rate (e.g., lb/MMBtu) for each hour and divide the sum by 

the total hours within a 30-day averaging period to determine compliance. Commenter states that these 

conflicting methods can yield very different results and may be subject to review if the EPA decides 

now to reopen the averaging times established under MATS.
78

Response to Comments 79 - 81: We do not agree with the commenters’ position that the existing 

source MACT limits are flawed because the EPA finalized a work practice standard for startup and 

shutdown periods. In addition, comments on the existing source standards are outside the scope of this 

rulemaking because we are not reconsidering those standards. Furthermore, the argument raised in these 

comments could have been raised in the challenges to the final MATS rule that was recently concluded 

in the D.C. Circuit. See White Stallion Energy Center v. EPA. In addition, as stated in the preamble and 

this RTC, we believe that the work practice standard in the final rule may result in HAP emissions that 

are less than the HAP emissions that may be emitted when the numerical standards apply, but that in any 

case the emissions will be comparable when averaged over the entire startup period. For these reasons, 

we maintain that the numerical limits adequately and appropriately account for variability whether or not 

the sources are required to include HAP emissions during startup and shutdown periods.

Substantively, commenters make a number of unproven and unsupported assertions about the amount of 

emissions during startup. For example, one commenter assumes based on its examples that HAP 

emissions during startup are always higher than at other periods of time. But at the same time, the 

commenter notes that we have no data on HAP emissions during startup and shutdown periods. The best 

performing sources in the category most likely have HAP emissions that are lower during the startup 

period as we have defined it because they are using clean fuels up to the time that they add coal to the 

boiler and they turn on their APCDs at the same time. Due to the inherently low HAP content of clean 

fuels like distillate oil and natural gas, it is likely that those best performing sources are emitting below 

the existing source standards in the final rule during that period. Furthermore, the record indicates that 

even before MATS virtually all EGUs were starting using clean fuels. Even with the additional 4 hours 

after generation necessary to ensure the sources’ ability to accurately measure HAP emissions, we 

believe that the continued clean fuel use during that 4 hour period will offset any HAP emissions from 

the coal- or solid-oil derived fuel, particularly if averaged over the entire startup period which will in 

many cases have longer periods of time where only clean fuels are combusted. So the record is not clear 

that HAP emissions during startup and shutdown periods at the best performing EGUs are actually 

higher than during normal operations. The EPA is requiring sources that measure HAP emissions with 

sorbent traps and/or CEMS to measure emissions during startup and shutdown periods so that we can 

obtain some data on HAP emissions during those periods, even if those data may have some uncertainty 

and the data are not used for compliance determination purposes.9 As the EPA stated in the proposed 

rule, we hope to have sufficient HAP emissions data for the CAA sections 112(d)(6) and (f) reviews to 

determine whether numerical standards are feasible and appropriate for periods of startup and shutdown.

Compliance is assured through the provisions of 40 CFR 63.10032(f) (records of the occurrence and 

duration of each startup or shutdown), 40 CFR 63.10032(i) (records of the type(s) and amount(s) of fuel 

used during each startup or shutdown), and 40 CFR 63.10020(b) (operate and collect data at all times the 

EGU is operating).

Concerning comments that HAP emissions can be measured during startup periods, the EPA is unaware 

of HAP measurement methodologies that can be used to accurately measure HAP emissions during 

those periods at EGUs (even sorbent traps may be problematic due to emissions flow during startup and 

shutdown). The commenter is correct that there have been HAP testing studies that addressed emission 

 

9 CEMS are certified at low, medium, and high load levels, but not during periods of startup or 

shutdown as defined in the final rule.
79

flow and other issues associated with testing during startup periods, but the testing issues are not 

resolved for broad application and the costs of the tests are significantly more expensive than the already 

expensive certified HAP testing required in the rule methodologies. 

The EPA also disagrees with the notion that EGUs will not have to do anything to comply with the final 

work practice requirements. Sources that do not have sufficient clean fuel capacity will have to increase 

that capacity. Sources will have to utilize the clean fuel for a longer period of time and to a greater 

degree. Finally, sources may determine that additional physical changes may be necessary to ensure that 

sources will be able to engage and operate their controls within the time necessary to comply with the 

numerical standards at the end of startup.

1.2.4 Legal issues

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 82: Commenter 20427 states that the startup exemption is based on industry’s desire that 

every EGU, even those of older design, be able to achieve the work practice standard without any 

investment in improved pollution control. Commenter states that the statute does not allow the EPA to 

set a standard of universal, low-cost achievability for the statutory requirement of controls reflecting the 

maximum reduction achievable (cited Sierra Club v. EPA, 2007).

Commenter 20422 states CAA section 112 is designed to reduce HAP emissions using APCDs that are 

based on best available technology. Commenter states MACT is intended to advance facility operations 

to keep pace with technological advancements in APCDs. Commenter states unless industry can 

demonstrate that plants that comprise the floor will not be able to meet the limit, which industry has not 

done, it is irrelevant whether other EGUs are unable to meet the limit. Commenter states industry 

commenters have not presented any data to show that any plant in the floor will be unable to meet 30-

day emission limits, because of startup emissions or for any other reason.

Commenter 20422 states the EPA must reconcile any expansion of startup exemption with the D.C. 

Circuit ruling that HAP emission limits under CAA section 112 must apply at all times (cited Sierra 

Club v. EPA, 2008). Commenter states that the EPA’s proposal to exempt post-generation emissions 

from compliance with CAA section 112 emission limits violates this clear requirement. Commenter 

states that neither industry nor the EPA have explained how this requirement can be satisfied by 

expanding the exemptions during startup already in the final rule. Commenter notes that the EPA cited a 

40-year old case, Portland Cement v. Ruckelshaus, 1973) that predates the Sierra Club 2008 decision 

and relies on language in a different section of the CAA that is not identical to the CAA section 112 

mandate that emission limits apply continuously. Commenter further notes that the EPA found that the 

emission standard could accommodate any variability in emissions that might occur after dispatch of 

electricity. Commenter states industry comments cited in the June 2013 notice do not reference the 

Sierra Club 2008 decision and do not explain how the EPA might expand the startup exemption 

consistent with that opinion and the EPA’s duty to establish and enforce CAA section 112 standards on 

a continuous basis. Commenter states it did not challenge the startup exemption in the final rule because 

it was narrowly tailored, limited to a few hours of combustion, and required use of clean fuels. 

Commenter states it reserves the right to seek judicial review of any decision to lengthen the startup 

period during which emission limits would not apply or authorize use of coal prior to the generation of 
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electricity, which would result in emissions well above the standards that apply during so-called normal 

operations. Commenter states that in any case, the EPA will need to explain how such a decision is 

consistent with Sierra Club v. EPA, 2008. Commenter 20436 states a similar position.

Commenter 20427 states the work practice standards exempting EGUs from compliance with numeric 

standards during coal-fired operations are unlawful. Commenter states the EPA has not found, and could 

not lawfully find, that a numeric emissions standard is infeasible during startup. Commenter states that 

CAA section 112(h) allows the EPA to substitute a work practice standard for a numeric emissions 

standard only where it is not feasible to prescribe or enforce an emission standard, i.e., a HAP cannot be 

emitted through a conveyance designed and constructed to emit or capture the pollutant, or if the 

conveyance would be consistent with Federal, State, or local law, or the application of measurement 

methodology is not practicable due to technological or economic limitations. Commenter states APCD 

methods are readily available to capture each pollutant and there are technically and economically 

feasible measurement methodologies available to measure those pollutants. Commenter states the EPA

cannot justify an expanded exemption from the numeric limits under that legal standard and cannot 

justify any exemption from numeric limits during coal- and oil-fired operations. Commenter states the 

EPA has not made a determination that the measurement or capture of Hg, PM, or acid gases from coaland oil-fired plants is not feasible. Commenter states that if the EPA were to make that determination, it 

would be obligated under CAA section 112(h) to specify a “particular class of sources” to which the 

determination applied; an overbroad work practice standard, applying to classes for which the EPA has 

not made a well-supported determination of infeasibility under CAA section 112(h), would be unlawful. 

Commenter states the EPA’s rationale to support its work practice standard, i.e., that there is not 

sufficient data on emissions during startup and shutdown, has no bearing upon that governing legal 

standard (i.e., the feasibility of capture and measurement of emissions). In fact, commenter states that 

the reconsideration record (an hour-by-hour analysis of startup events using emissions, heat input, and 

electric output data) directly contradicts the proffered rationale, in that the reconsideration is premised 

upon the data whose absence provide the rationale for the EPA’s original refusal to impose numeric 

standards.

Commenter 20422 states the EPA has not proposed new work practice standards in lieu of emission 

limits, has no evidence to support such a proposal. Commenter states CAA section 112(h) allows the 

EPA to substitute a work practice standard for a numeric emissions standard only where it is not feasible 

to prescribe or enforce an emission standard. Commenter states the EPA’s June 2013 notice does not 

propose or justify such an action, identify any specific work practices it may substitute for emission 

limits, or give the public an opportunity to review and comment on a specific proposal. Commenter 

states the EPA needs to explain how the specific work practice standards satisfy the requirements of 

CAA section 112(h). Commenter alleges that the EPA may not base any work practice proposal on a 

scattering of self-serving and incomplete anecdotes offered by industry commenters 20 months after the 

final rule was promulgated. As an example, commenter states that although industry raises concerns 

about access to clean fuels during startup, the EPA must determine whether more than 12 percent of 

coal-burning EGUs already have the needed capacity and if so, that defines the MACT floor and other 

facilities must invest in upgrades that increase their use of clean fuels (also noting that the EPA has not 

demonstrated that partial operation of pollution controls for a few hours after electricity is generated 

makes compliance with emission standards “not infeasible” within the meaning of CAA section 112(h)).
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Commenter 20427 states the work practice standards under consideration violate CAA section 112(d). 

Commenters 20422 and 20427 state that CAA section 112(h) requires any work practice that substitutes 

for an emission standard under CAA section 112(d) to be consistent with the provisions of subsection 

(d), i.e., work practice standards must obtain the “maximum degree of reduction in emissions” that is 

“achievable”.” Commenters 20422 and 20427 state the “maximum degree of reduction” for new sources 

and the standards for existing sources cannot be “less stringent than the emissions control that is 

achieved in practice by the best controlled similar source” and cannot be less stringent than “the average 

emission limitation achieved by the best performing 12 percent of the existing sources,” respectively.

Commenter 20427 states the work practice standards under consideration do not meet those 

requirements. Commenter states the EPA has made no effort to square its work practices for startup with 

any of the governing legal standards. Commenter states the record suggests only that handful of older 

EGUs would need to improve their APCD in order to meet the standards in the final rule; most existing 

EGUs and any new EGU using readily available ACPD technologies can operation PM, Hg, and acid 

gas APCDs at all times coal is burned; and coal-fired EGUs can meet the numeric limits whenever they 

generate electricity. Commenter states the EPA has not and cannot demonstrate that any of the work 

practice standards it has proposed or considered during the rulemaking (except for clean fuels 

requirement) reflect the maximum achievable reduction in toxic emissions. Commenter states industry 

comments ask for a work practice that can be met by all EGUs, with no improvement in the APCD 

equipment installed in EGUs of older design, but further states the D.C. circuit has firmly established the 

EPA may not set its MACT standards “at the worst emission level experienced by any source using the 

MACT control” (cited Cement Kiln Recycling Coalition v. EPA, D.C. Cir. 2001). Commenter states the 

EPA cannot set its standard to reflect the emissions experienced by sources that lack state-of-the-art 

controls.

Commenter 20422 states the rulemaking record and industry comments does not provide any basis for 

substituting work practice standards for the emission limits that apply after boilers begin generating 

electricity.

Response to Comment 82: The commenter asserts that the final work practice standard is set at a level 

that all sources can meet, but that assertion is not supported by the information in the docket, most 

significantly the Revised TSD. As discussed above, the requirement to maximize the use of clean fuels 

during startup and to engage the PM controls within one hour will result in HAP emissions that are 

likely comparable to if not below the final standards due to the inherently low levels of HAP emissions 

attendant to the use of clean fuels. Any source that is not currently equipped with clean fuel capacity 

sufficient to bring the PM controls up to temperature will have to invest in additional clean fuel capacity.

The commenter also incorrectly asserts that CAA section 112 standards must involve APCDs. That is 

not correct, and, in any case, commenter has not identified any APCD that would operate during startup 

much less one that would have HAP emissions lower than achieved through the use of clean fuels.

The commenter incorrectly characterizes the startup and shutdown work practice as an exemption and 

then cites case law to support its argument that the numerical standards must apply at all times. But the 

cited case concerned an actual exemption. The February 2012 final MATS rule did not contain any 

exemptions and no exemptions are added through this final action on reconsideration. Instead, the EPA’s 

MATS rule has numerical standards that apply at all times except during startup and shutdown as 
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defined in this final rule. During those periods, EGUs are required to comply with work practice 

standards issued pursuant to CAA section 112(h). The work practice was established by evaluating the 

performance of the best performing sources as determined by the EPA.

The commenter asserts without data from the best performing units, that the work practice we finalized 

today will cause more HAP emissions than if the numerical emissions limits applied during those 

periods. As discussed above, we question that assertion and believe it likely that HAP emissions during 

startup and shutdown under the final rule will be lower than required by the numerical standards.

Finally, the EPA complied with the requirements of CAA section 112(h) when determining that a work 

practice is authorized for startup and shutdown periods and in the establishment of the final work 

practice. In the February 2012 final MATS rule, the EPA indicated that it was establishing a work 

practice standard for startup and shutdown periods because the EPA did not have HAP emissions data 

during such periods. We did not receive any petitions for reconsideration that questioned the CAA 

section 112(h) authority to establish a work practice standard from these or any other commenters, and, 

for that reason, we did not address the issue in further detail in the proposed reconsideration rule. Since 

that time, we have confirmed that in addition to the lack of HAP emissions data for periods of startup 

and shutdown, we do not have measurement methodologies that are currently able to accurately measure 

HAP emissions during periods of startup and shutdown. We maintain that collectively these conclusions 

support a determination that “the application of measurement methodology to [EGUs] is not practical 

due to technological and economic limitations,” consistent with CAA section 112(h)(2)(B).

Commenters’ assertions that testing methodologies are available for HAP emissions are not supported in 

the record, and the technological difficulties associated with accurately measuring HAP emissions 

cannot be immediately resolved for EGUs, notwithstanding whether in the future the EPA will have the 

ability to accurately measure such emissions because the technological issues associated with capturing 

and measuring a representative sample may be addressed.

The EPA also maintains that it would be very difficult to prescribe and enforce numeric emission limits 

during startup and shutdown periods because of the testing issues that currently exist. See CAA section 

112(h)(1). Conversely, the work practice that the EPA is finalizing today will be enforceable, and, 

contrary to assertions of the commenters, will achieve significant HAP emission reductions from EGUs 

during periods of startup and shutdown. We also maintain that the final work practice is consistent with 

CAA section 112(d) because it is based on the performance of the best performing EGUs.

Comment 83: Commenter 20421 states that “startup period” does not constitute an emission standard, 

but is a defined term. Commenter maintains that the term “startup period” describes a basic boiler 

operation that is determined by a number of factors including boiler design, function, fuel, associated 

peripheral equipment and other factors; these factors combined establish for each EGU what constitutes 

“startup.” Commenter states that because the definition of startup is not an emission standard, it does not 

fall under the purview of the CAA section 112(d) focus on the average of the best performing sources, 

and the EPA cannot ignore subpopulations of covered sources when defining terms applicable to all 

covered sources. Commenter states that in order for the rule to be rational, it must begin by correctly 

defining the mode of operation, and the definition must be capacious enough to accurately define that 

mode for every boiler regulated by the rule – standards can then be applied to regulate emissions during 

the startup period. 
83

Commenter 20421 states that the “startup period” at a power plant also reflects a specific level of

engagement by engineers and others responsible for plant operations. Commenter notes that plant 

operators interface with the machinery in a power plant on three well-understood levels: monitor, 

control, and diagnostic – as the plant moves from one level to the next, plant operators adjust their 

interface as appropriate for each level and undertake different tasks and different responsibilities. 

Commenter maintains that at the monitor level, operators monitor overarching parameters to ensure that 

the plant is meeting the parameters within an acceptable performance band, representing satisfactory 

performance of the overall plant and its critical systems and that in this monitor mode, the operator’s 

role is mostly passive and reactive. Commenter indicates that during control mode, operators actively 

engage with plant systems – for example, starting equipment, changing valve positions, performing 

adjustments – to affirmatively alter operating conditions to move the plant toward a different 

configuration or to implement a specific procedure that requires a series of adjustments to plant systems. 

Commenter states that the diagnostic mode begins when troubleshooting is called for and that as a 

practical matter and viewed from the perspective of the plant operators, the startup period requires full 

engagement by plant personnel in control mode. Commenter states that control mode for startup does 

not conclude until all systems and equipment required for normal, steady state operation, including 

APCDs, have been placed into service and the plant is capable of steady state operation at its minimum 

load level – only at that point can plant operators shift to monitor mode, monitoring plant performance 

with specified parameters.

Commenter 20421 states that the EPA’s definition of startup as a percent load plus a period of time may 

accurately describe the timeframe during which plant personnel are in control mode for startup at a 

majority of power plants. However, commenter alleges that the timeframe is arbitrary as applied to 

plants where plant operators are still fully engaged in control mode for startup beyond the period of time 

the EPA identifies – at those plants, operators may still be in control mode for startup, with the 

responsibility for overseeing and actively adjusting plant systems to satisfy the requirements of the 

startup procedure, at a time when the EPA’s definition declares startup complete. Commenter maintains 

that from a plant operations perspective, that definition is completely arbitrary and does not reflect the 

continuing control mode of the plant operations. Therefore, to more precisely reflect this condition, 

commenter states that the EPA should define the end of startup to correspond with the point when boiler 

operating conditions have stabilized and all APCDs are in service; if a timeframe must be utilized, the 

EPA should define startup to include a longer period of time under unusual circumstances. In this 

scenario, commenter requests that this additional language in quotes be inserted to define the end of 

startup as 

4 (or 3) hours after 25-percent load is first reached or 12 (or 6) hours after first electricity 

generation, whichever occurs first, “or in limited circumstances beyond those times when 

the permissive temperatures for an APCD extends beyond the periods of time used to 

define the end of startup.”

Response to Comment 83: In this final rule, the EPA is establishing definitions for startup and 

shutdown designed specifically to function as part of the work practice standards. The definitions

are necessary to define the period when the work practice will apply in lieu of the numerical 

standards. We are unclear about what the commenter’s issue is with our use of definitions in this 

manner, but they provide no legal basis to support their claim that we erred by doing so.
84

The remainder of the comment appears to be an argument for a more flexible standard that would 

likely allow sources to set their own schedule without change. As explained above, we do not 

think that is consistent with the statute because work practice standards are required to be 

consistent with CAA sections 112(d) or (f) and only available when it is infeasible to measure 

HAP emissions. The EPA acknowledges that plant operators may be “fully engaged” in adjusting 

their system beyond the defined end of startup in the final rule. However, as noted elsewhere in 

this document, the EPA believes that its analysis of the startup practices of the top performing 

EGUs and its final definition of “startup” adequately balances commenters’ concerns with the 

requirements of CAA section 112. The EPA also notes that the goal of the Revised TSD analysis 

was to identify the approximate time it took, on average, to initiate operation of APCDs by the 

top performing 12 percent of EGUs to determine the appropriate time to end the startup period

because we believe at that time sources will be able to capture and adequately measure HAP 

emissions using continuous emissions monitoring systems. The goal was not to seek the time it 

took for APCDs at all EGUs to become operational, as that approach would not be consistent 

with the statute, nor do we require that the identified controls be functioning at the end of startup.

Instead, we require sources to comply with the numerical emissions limits at that time in 

whatever manner necessary, including engagement of controls and/or continued use of clean 

fuels.

1.2.5 Common stack

Summary of Comments Received Following November 30, 2012, Proposal

Comment 84: Commenters 20256, 20277, 20281, and 20294 state that the proposed rule does not 

resolve how the startup and shutdown definitions and work practice provisions apply to EGUs that share 

a common stack. Commenters recommend that the rule should make clear that the emission limits do not 

apply unless all EGUs sharing the common stack are not starting up or shutting down. Commenter

20277 states that EGUs that share a common stack have the option of monitoring in the common stack 

and demonstrating compliance based on their combined emissions (40 CFR 63.10010(a)(2)).

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 85: Commenters 20387, 20397, 20398, 20408, 20425, and 20428 state that the EPA should 

exempt all EGUs on a common stack from emission standards for periods when any EGU sharing the 

common stack is starting up or shutting down. Commenter 20387 indicates that to do otherwise would 

create scenarios both many and confusing because of the number and type of EGUs that may exhaust 

through a common stack as well as the variety of APCDs (in common and/or otherwise).

Commenters 20399 and 20408 state that there is no way to accurately apportion emission rates back to 

the individual EGUs or assess the emissions contribution an EGU in startup has on the performance of a 

control device to accurately report emission rates for the EGU operating outside of startup. Commenters 

20399, 20408, and 20409 ask that all emissions occurring during a startup or shutdown should be 

exempted from the 30-boiler operating day rolling average.

Commenter 20428 states that EGUs that share a common stack have the option of monitoring in the 

common stack and demonstrating compliance based on their combined emissions. Commenter notes 
85

that, although the work practice standards required during EGU startup and shutdown can be applied 

separately on each EGU, emission controls necessary to meet applicable emission standards at the 

common stack may not be operating, or operating at the necessary efficiency, during an EGU’s startup 

and shutdown process; that could be true regardless of whether the EGUs on a common stack share all 

control devices, or have some individual controls. Commenter provides data for three EGUs sharing a 

common stack; data are shown for two EGUs already in operation with startup of the third EGU that is 

equipped with its own SCR. Commenter 20428 notes that Hg emissions measured in the common stack 

spike as the third EGU starts up before its SCR is operational. Commenters 20408 and 20428 note 

similar PM emission spikes for common stacks when one EGU is starting up, and potentially after an

EGU shuts down. Commenter 20428 states that, given the variable and significant change in measured 

emissions through a common stack when one EGU sharing the stack startups (or shuts down), the 

MATS rule should make clear that the numerical emission limits do not apply to any of the EGUs 

sharing the common stack, if any one EGU on the common stack is starting up or shutting down.

Commenter 20408 notes that EGU’s with individual stacks are not required to monitor emissions after 

an EGU enters shutdown. For a common stack, commenter states that the MATS rule currently requires 

emissions monitoring any time any of the EGUs are operating which can be particularly difficult for 

continuous PM monitoring. Commenter indicates that when an EGU goes offline, there is a period of up 

to 8 hours when air flow is maintained high through the EGU to cool it in preparation for maintenance; 

because of shedding of ash in the EGU and ductwork during cool down and diluted CO2 emissions, 

calculated PM (as well as HCl and Hg) emission rates will appear to be high and will not be correct for 

an EGU or EGUs that were operating normally during this period. Commenter recommends that the 

EPA consider excluding up to 8 hours of monitored data after an EGU has shutdown in a common stack 

configuration.

Commenter 20398 notes there is no obvious solution to calculating SS emissions from a common stack 

that does not involve installing separate monitoring systems at great expense.

Commenter 20421 supports language to address startup and shutdown impacts for common stacks. 

Commenter states that in order to accurately attribute emissions from each boiler, the periods when one 

boiler is in startup or shutdown should exclude the emissions measured at the common stack from the 

MATS air emission limits.

Commenters 20417 and 20419 support commenters that have interpreted how the startup and shutdown 

definitions and work practice provisions apply to EGUs that share a common stack. Commenters agree 

that although work practice standards would be applied separately to each EGU that shares a common 

stack, numerical emission limits should not apply if one EGU sharing a common stack is starting up or 

shutting down. Commenters state this is the only way for EGUs which share a common stack to comply 

with the prohibition on the use of data recorded during startup or shutdown to demonstrate continuous 

compliance. Commenters say, further, application of numerical emissions limits while one EGU sharing 

a common stack is starting up or shutting down defeats the purpose of providing work practice standards 

during periods of startup and shutdown.

Commenter 20420 states that MATS is not clear on how the work practice standards should be applied 

when one EGU venting to a common stack is starting up or shutting down while another EGU venting to 

the common stack is in operation. Commenter states that when emissions are being measured in the 
86

common stack, emissions from the EGU starting up or shutting down cannot be differentiated from the 

EGUs that are operating normally. Commenter states that the startup and shutdown work practice 

standards should apply to all EGUs venting to a common stack when any one of the EGUs is starting up 

or shutting down while any other EGU is in operation.

Commenter 20403 supports language to address startup and shutdown impacts for common stacks. 

Commenter states that the startup and shutdown of a boiler that shares a common stack with another 

boiler will impact the emissions in the common stack. Commenter states that due to this impact the 

periods when one boiler is in startup or shutdown should exclude the emissions measured at the common 

stack from the MATS air emission limits. Commenter suggests that additional language be added stating 

that the boiler remaining in operation maintains its APCD throughout the period during which the other 

boiler is starting up or shutting down.

Commenter 20391 states that the rule must reconcile application of startup and shutdown provisions to 

common stacks. Commenter states that the proposed reconsideration rule also does not resolve how the 

startup and shutdown definitions and work practice provisions apply to EGUs that share a common 

stack. Commenter states that EGUs that share a common stack have the option of monitoring in the 

common stack and demonstrating compliance based on their combined emissions. Commenter states

that although the work practice standards can be applied separately on each EGU, emission controls 

necessary to meet applicable emission standards at the common stack may not be operating, or operating 

at the necessary efficiency, during an EGU’s startup and shutdown process (regardless of whether the 

EGUs on a common stack share all control devices or have some individual controls). Commenter states

that for this reason, the rule should make clear that the emission limits do not apply to any of the EGUs 

sharing a common stack flue if any one EGU on the common stack is in the process of starting up or 

shutting down.

Commenter 20391 states that the current definition of shutdown in the MATS rule starts when either 

none of the steam from the boiler is used to generate electricity for sale over the grid or for any other 

purpose, or at the point of no fuel being fired in the boiler, whichever is earlier, and ends when there is 

both no electricity being generated and no fuel being fired. Commenter states that for a single stack, 

there are no further reporting requirements after no fire or no generation, even though there is still hot 

gas being emitted through the stack with the continued operation of fans until cool down. Commenter 

states that on a common stack, however, you can have one EGU operating and the other shut down with 

hot gases being emitted in the common stack until the fans are shutdown. Commenter states that 

consequently, there can be significant spikes in PM emissions in the common stack during a shutdown 

until the fans of the shutdown EGU are turned off. Commenter states that, therefore, the EPA should 

define shutdown as beginning with the end of firing fuel or no generation, and ending when the ID fans 

of the shutdown EGU are turned off.

Commenter 20399 states that numerical emission limits should not apply if any one EGU sharing a 

common stack is starting up or shutting down. Commenter urges the EPA to not attempt to calculate 

startup and shutdown emissions from common stacks, but rather apply its proposed startup and 

shutdown language anytime any one EGU that shares a common stack with another affected EGU starts 

up or shuts down. Commenter states that the effect of low diluent gas concentrations and electrical loads 

of zero from the EGU in startup further complicates the issue of common stack emission rates with one 

EGU in startup.
87

Commenter 20400 states that the proposed reconsideration rule does not clearly resolve how the startup 

and shutdown definitions and work practice provisions apply to EGUs that share a common stack and 

common emissions controls.

Commenter 20400 states that it’s Allen and Marshall Stations are examples of this situation. Commenter 

states that at Allen, three EGUs share one common FGD system and exhaust into one stack flue, and the 

other two EGUs share another common FGD system and exhaust into a second stack flue. Commenter 

states that Marshall Units 1 and 2 share a common FGD system and a single stack flue, whereas Units 3 

and 4 each have their own FGD system and stack flue. Commenter states that each of the generating 

EGUs at Marshall and Allen has its own particulate control system, which is operated during startup and 

shutdown in accordance with good practice as defined in a state-approved work practice manual. 

Commenter states that the Allen units and Marshall Units 1 and 2 have no SCR (SNCR and low NOx 

burners are used for NOx control), but any future installation of SCR would most likely include a 

separate SCR for each EGU. Commenter states that in each of these installations, the CEMS are located 

on the common flue for each EGU or group of EGUs sharing an FGD system, and all emissions 

compliance tests are performed on these common flues.

Commenter 20400 states that under the current MATS rule, compliance with emissions standards for 

affected EGUs sharing a common stack (that is, through the same exhaust flue) may be determined as if 

the group of EGUs was a single source (40 CFR 63.10009(l)), and in that case the measured emissions 

rate must be assigned to each EGU that shares the common stack. Commenter states that however, the 

work practice standards for startup and shutdown apply to each individual EGU. Commenter supports 

applying the work practice standards at an EGU level. Commenter notes that is important because the 

startup or shutdown of each individual EGU creates a process imbalance that will affect emissions, and 

the contribution to the measured stack emissions from that startup will render the measurement not 

representative of normal operation.

Commenter 20400 recommends that all periods should be excluded from the compliance averages 

whenever one or more affected EGUs sharing a common stack is considered in startup or shutdown. 

Commenter states that for example, if the EPA defines startup as the period from initial combustion of 

fuel through 25 percent of the maximum load on an EGU plus 3 hours, that criteria would apply when 

any of the individual EGUs feeding a common flue meet that criteria, or if any EGU is considered in a 

shutdown.

Commenter 20400 states that including periods of startup and shutdown in an output-based measured 

emissions rate would present particular problems when one EGU is in startup or shutdown and is not 

generating electricity. Commenter states that in those situations, emissions from the EGU in startup or 

shutdown would be included in the compliance average for the other on-line EGUs but the denominator 

would not include any generation associated with that EGU. Commenter states that compliance with an 

input-based standard would also be impacted because the flue gas from the EGU in startup or shutdown 

will be subject to process imbalance, which may impact either the performance of the control equipment 

or the ability to accurately measure emissions. Commenter states that it would be inappropriate to 

conduct an emissions test during these unstable and non-routine conditions. Commenter states that also, 

the ICR database used to develop the MATS standards did not include any data obtained during periods 

where one or more EGUs tied to a common stack were in startup or shutdown conditions. Commenter 
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states that as a result the EPA had no emissions data or CEMS data during those periods so that it could 

appropriately set emissions limits during these periods where the emissions control equipment is not 

functioning at its intended design conditions. Commenter states that the EPA should therefore consider 

these periods as being subject to the work practice standards and not included that data when 

determining compliance averages.

Commenter 20400 recommends that the EPA use the following approaches to address startup and 

shutdown emissions for EGUs that share a common stack:

• For affected EGUs the either share a common final control device such as an FGD, or 

have completely separate control devices, share a common stack, and report a single 

measure value from CEMS, define startup and shutdown periods as any period of time 

where any of the individual generating EGUs meets the criteria for startup and shutdown. 

For example, if the EPA defines startup for a single EGU as the period from initial firing 

of fuel through 25 percent of maximum generating capacity plus 3 hours (not to exceed 6 

hours after start of generation), the startup exclusion would apply to any data gathered on 

a common stack where any of the EGUs has begun to combust fuel and has not reached 

25 percent load plus 3 hours or 6 hours after the EGU has begun generating electricity. 

For shutdown, data would be excluded whenever any of the common EGUs ceases to 

generate electricity until the EGU ceases to fire fuel. This approach is particularly 

important in cases where EGUs do not share a final control device. In such cases, a 

smaller EGU that has completed a startup could be outstripped by the starting of a larger 

EGU when the second EGU’s control equipment has not reached its full effectiveness.

• Work practice standards will apply individually to each EGU during its startups and 

shutdowns to provide assurance that all control systems will be operated at all times coal 

is combusted in accordance with best practice.

• Because the rule requires that CEMS be operated at all times, if an EGU is in startup or 

begins startup after the startup period has ended for one or more of the other common 

EGUs, the CEMS DAHS should still substitute a default generation value (MW) for the 

EGU in startup. As noted separately in our comments, commenter recommends a default 

value of 5 percent of rated capacity for any period where an EGU is combusting fuel but 

the electrical generation is below the default value. Likewise, if an EGU initiates 

shutdown while one or more EGUs remain on-line, the default generation value should be 

included for that EGU until the shutdown concludes (the EGU ceases to combust fuel or 

the EGU comes back on-line).

Commenter 20415 states that if CEMS or sorbent trap monitoring systems are utilized on a common 

stack and one or more of the EGUs feeding that stack are in startup or shutdown mode, then the 

emissions indications in the common stack are not indicative of normal operation of any of the EGUs. 

Commenter states that this situation could be avoided with use of monitoring systems on every 

individual boiler, but such installations are very expensive and duct arrangements might not be able to 

accommodate the monitors, so there are legitimate reasons to use monitoring on the common stack. 

Commenter states that in such situations, it recommends that the EPA consider use of parametric 

monitoring or other parameters to indicate normal operation of the boiler(s) that are not in SS mode 
89

while one or more other boilers are in SS, with the monitoring data during that period not used for

compliance purposes. Commenter states that then when the SS period ends, emissions data would be 

included in the compliance data set.

Commenter 20426 requests that the EPA clarify that the time period associated with each individual 

EGU sharing a common stack be considered “startup,” and that these times are to be excluded from 

MATS compliance demonstrations.

Commenter 20429 states that exempt excess emissions from an EGU in SS on a common stack may 

cause the stack as a whole to exceed emission limits. Commenter believes the rule should clearly state 

that emission limits for EGUs on a common stack do not apply to any of the EGUs if any one EGU on 

the common stack is in SS mode.

Commenter 20431 states that that EGUs that share a common stack have the option of monitoring in the 

common stack and demonstrating compliance based on their combined emissions. 40 CFR 

63.10010(a)(2). Commenter states that because its Bailly Generating Station has two EGUs that share a 

common stack, those EGUs are directly affected by the definition in this part of the rule. Commenter 

states that although the work practice standards required during EGU startup and shutdown can be 

applied separately on each EGU, emission controls necessary to meet applicable emission standards at 

the common stack may not be operating, or operating at the necessary efficiency, during the EGU

startup and shutdown process. Commenter states that this is true regardless of whether the EGUs on a 

common stack share a control device (e.g., FGD), or have some individual controls, as in the case of the 

Bailly Station generating EGUs. Commenter states that for this reason, the rule should make clear that 

the emission limits do not apply to any of the EGUs sharing the common stack, if any one EGU on the 

common stack is starting up or shutting down.

Comment 86: Commenter 20427 states that many older EGUs use shared stacks and an expanded 

exemption would increase pollution; if all EGUs were exempted when any one EGU is within 4 to 12 

hours of startup, the EGUs would largely avoid the numeric standards. Commenter citing a facility with 

3 EGUs that share a common stack, indicates that, individually, startup defined as 4 hours past 25 

percent load would exempt numeric limits for a total of 476 hours (164 hours, 143 hours, and 169 hours 

for each of the 3 EGUs). Commenter then notes that exempting numeric limits when any one EGU fell 

within the startup period would allow the EGUs to operate for 412 hours (each) without numeric limits, 

and a total of 1,236 hours (provides an attachment to its comment letter, with hour-by-hour operating 

data and startups on 3 EGUs sharing a common stack at 1 facility for 2011). Commenter states there are 

over 100 EGUs where at least 3 or more EGUs share a common stack.

Commenter 20427 states there is no reason for the proposed expansion of the startup definition to cover 

common stacks, and that measurement device placement allows measurement of emissions from 

individual EGUs, even where EGUs share a stack. Commenter states that concerns can be solved by 

requiring emission and flow measurement in the duct from each EGU prior to combination in the 

common stack or flue. Commenter states that geometry constraints can be addressed by ductwork 

retrofits, very few EGUs would be incapable of conducting the retrofits, and any expansion in the startup 

work practice should be limited to only those EGUs incapable of measuring emissions from individual 

stacks, not all EGUs using a shared stack.
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Commenter 20422 notes that EGUs have 2 options for monitoring emission rates for common stack 

EGUs: EGUs can monitor individual EGU emissions at the duct leading to the common stack, or 

monitor the common stack and attribute the average recorded emission rate to all of the EGUs that share 

the common stack. If EGU operators have concerns about emissions from other EGUs that share the 

common stack during startup or shutdown, commenter states industry has the option to monitor 

individual EGU emissions at the duct leading to the common stack and can thus easily avoid any 

problem related to emissions from other EGUs sharing the common stacks affecting their ability to 

comply

Commenter 20433 rebutted Commenter 20422’s assertion that it would be “easy” to monitor at the duct 

leading to the common stack as being inaccurate and shows a basic misunderstanding of the character of 

the ductwork leading to many common stacks. Commenter 20433 notes that the sampling locations 

available in most utility ductwork arrangements are far from ideal and that the ductwork leading to the 

common stack generally does not have an appropriate location in the ductwork, the access, and/or the 

platforms necessary to support the monitoring systems, much less the reference method testing required 

to certify and to maintain the systems. Commenter 20433 states that over the years, the utility industry 

has spent millions of dollars installing elevators, constructing platforms, and installing sampling ports at 

proper stack sampling locations, which are most often within the common stack (for common stack 

EGUs) and maintains that ducts leading to common stacks often do not meet the minimum sample 

location criteria set forth in 40 CFR Part 60, Appendix A, Method 1, Section 11, which requires 

minimum siting criteria when locating testing locations on a duct or stack. Commenter 20433 notes that 

EPA Performance Specification 2 in 40 CFR Part 60 Appendix B requires a minimum of two duct 

diameters downstream from the nearest control device and a half duct diameter upstream from the 

effluent exhaust or control device and that the majority of common stack EGUs were built without 

regard for CEMS siting in the ductwork, and there is simply not enough undisturbed duct lengths 

suitable for proper CEMS siting criteria. Commenter 20433 alleges that due to the physical 

configuration of an EGU, it is often not possible to reconfigure the ductwork to create an appropriate 

sampling location.

Comment 87: Commenter 20390 states that once startup and shutdown have been more clearly defined, 

the issue for EGUs with a common stack can be addressed. Commenter notes that, generally, the impact 

on the common stack emissions is relatively small as the EGU that is starting up is at minimal flow 

conditions when the total emissions are calculated. Commenter states that emission level would be 

impacted if relatively high load (e.g., 50 percent total capacity) is required prior to starting up APCD.

Response to Comments 84 - 87: Many commenters suggested that the February 2012 final rule was 

unclear with respect to startup and shutdown requirements for EGUs that shared a common stack. The 

EPA disagrees with those commenters. 40 CFR 63.10010(a)(2) of the final rule required owners or 

operators of EGUs with common stacks to either monitor the EGUs separately or monitor the common 

stack and assign the same emissions value to each EGU. The EPA did not include separate specific 

requirements for monitoring during periods of startup or shutdown because it was not necessary, and we 

continue to believe that sources should be required to monitor, record, and report emissions in a manner 

that ensures compliance with the standards at all times. The use of a common stack is a convenience for 

sources that may not be used as an excuse to avoid compliance assurance requirements, even if an 

additional cost is incurred for sources with a common stack. 
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As in the February 2012 final rule, owners and operators of EGUs with common stacks are required to 

monitor and report emissions at all times the EGUs are operating. Also, as with the February 2012 final 

rule, work practice standards apply during periods of startup or shutdown. Owners or operators of EGUs 

with common stacks may either monitor each EGU separately upstream of the common stack or from 

the common stack. Monitoring must be operational at all times that fuel is being combusted, and 

compliance with numeric emission limits is required except for units that are operating in periods of 

startup or shutdown. Should an owner or operator choose to monitor the common stack, then emissions 

obtained from the monitoring will be applied to every EGU in an operating mode other than startup or 

shutdown at the time of measurement. This approach remains consistent with that of the February 2012 

final rule, and is not expected to be problematic emissions-wise for any EGU using a common stack, 

because the EGUs in periods of startup or shutdown are required to use clean fuels and to operate their 

PM controls within 1 hour of primary fuel combustion and the EGUs operating not in periods of startup 

or shutdown are required operate such that they meet their emissions limits. And, as we have stated 

previously, it is our understanding that sources almost always operate their units to ensure a considerable 

compliance margin to ensure that they comply with emissions standards over a continuous period. The 

fact that sources are able to operate with a compliance margin generally demonstrates that the numerical 

standards include sufficient variability to address all operating conditions, including periods of startup 

and shutdown, and that the standards can be achieved in an economical manner.

As mentioned later, during startup or shutdown periods for EGUs using common stacks, the 

reconsidered rule also allows use of a default electrical load and default diluent values; use of these

values should further alleviate commenter concerns about low electrical output calculations.

As described above, there is no need to resolve how the startup and shutdown provisions apply to EGUs 

that share a common stack because the provisions of the February 2012 final rule, with some minor 

changes to address industry concerns, adequately address the applicable compliance assurance 

provisions. See 77 FR 9371, 9382 [concerning measurement instruments to be operated, emissions 

measured, and emissions reported during periods of startup and periods of shutdown]; 40 CFR 

63.10010(a)(2)(i) and (ii) [concerning use of measurement instruments in individual ducts leading to 

common stacks and in common stack measuring emissions from all EGUs]; and docket ID EPA-HQOAR-2009-0234-20126 (Volume 2, pages 22, 93, 359, 400, 424, 442, and 460).

More than one commenter suggested that every EGU sharing a common stack should be exempt from 

numeric emission limits when any EGU sharing the stack is in startup or shutdown mode. The EPA

disagrees with those comments. The reconsidered rule does not allow all the EGUs sharing a common 

stack to avoid compliance with the numeric emission limits when any one of those EGUs is in a period 

of startup or shutdown. We believe that such an allowance would constitute an improper exemption 

from the requirement for sources to comply with the applicable NESHAP standards at all times. Thus, 

EGUs venting to a common stack that are not in startup mode must continuously comply with the 

numerical limits, even while another EGU sharing the common stack is complying with the work 

practice requirements.

A number of commenters provided data that they allege supports the exclusion of data from periods of 

startup and shutdown on a common stack whenever any EGU sharing the stack is in startup or shutdown 

mode. As a preliminary matter, we note that these data were generated before the EGUs were required to 

comply with the final MATS standards (i.e., the numerical emission limits and the work practice 
92

requirements), and the commenters do not indicate that the EGUs were operating in compliance with the 

final standard at the time these data were collected. Furthermore, we do not know if the EGUs tested 

were among the best performers for either the numerical limits or the work practice requirements (e.g.,

did the EGUs startup on clean fuels alone). We further note that the data were collected over periods of 

time that are inconsistent with the final definition of startup. In any case, we continue to believe that 

HAP emissions during startup and shutdown periods at the best performing EGUs is as low as, or lower 

than, those levels required when the numerical limits apply. 

As demonstrated in the figures submitted by one commenter, PM emissions during startup periods as 

measured in a common stack by a CEMS that did not include use of a diluent cap are about one-half the 

PM limit on an hourly basis within 4 hours after generation starts. As demonstrated in another figure 

submitted by commenter 20428, hourly Hg emissions values during startup periods as measured in a 

common stack by a continuous monitoring system appear to be below the value of the emission limit 

within 12 hours of control device startup. Given the short 4 hour duration for startups after electricity 

generation and the low HAP emissions expected due to the work practice requirements, we believe 

EGUs using a common stack but not operating in periods of startup should be able to comply with the 

numeric standards. As demonstrated in a figure submitted by Commenter 20428, PM emissions during 

shutdown periods as measured in a common stack by a CEMS that did not include use of a diluent cap 

are at about the level of the PM limit on an hourly basis within 9 hours after generation ends for 11 of 15 

shutdown periods. Given the short duration for shutdowns (when compared to the 30-boiler operating 

day rolling average period of the emission limit), emissions from EGUs in a common stack but not 

operating in periods of shutdown do not appear to be problematic for compliance purposes, and, as with 

the data from startup periods, they were collected before the source was required to comply with the 

final work practice standard.

One commenter is incorrect in stating that EGUs with individual stacks are not required to monitor 

emissions during shutdown; Table 3 to subpart UUUUU requires EGUs to operate all continuous 

monitoring systems (CMS) during shutdown and section 63.10000(a) requires EGU owners or operators 

to meet the work practice requirements of Table 3.

The EPA disagrees with the suggestion by one commenter that no obvious solution exists to calculating 

startup or shutdown emissions from a common stack that does not involve installing separate monitors at 

great expense, for, as shown in figures submitted by another commenter, CEMS in common stacks 

appear to work well – even when diluent caps are not used.

Based on the figures submitted by one commenter, the EPA finds no reason not to continue to require 

assignation of emissions data from CEMS in a common stack to each EGU operating not in a period of 

startup or shutdown.

The EPA disagrees with commenters who suggest the only way for EGUs with monitoring in a common 

stack to comply with the prohibition against the use of data recorded during startup or shutdown is not to 

use those data when any EGU in the common stack is starting up or shutting down. EGUs not in startup 

or shutdown periods but in common stacks still have emissions; those emissions are subject to numerical 

emissions limits. Owners or operators who are concerned about applying the common stack monitoring 

values to individual EGUs can install separate monitors for each EGU upstream of the common stack.
93

With respect to the commenter who suggests that when emissions are being measured in the common 

stack, emissions from the EGU starting up or shutting down cannot be differentiated from the EGUs that 

are operating normally, the EPA notes that as mentioned above, owners or operators who are concerned 

about being able to differentiate individual EGU emissions in a common stack can install separate 

monitors for each EGU upstream of the common stack.

The EPA agrees that EGUs in periods other than startup or shutdown need to operate their air pollution 

control devices continuously, but the Agency disagrees that additional requirements in this rule are 

necessary. These requirements are already contained in 40 CFR 63.6(e)(1)(i) of the general provisions, 

and must be followed.

10

To the commenter who suggests that because emission controls necessary to meet applicable emission 

standards at the common stack may not be operating, or operating at the necessary efficiency, during an 

EGU’s startup and shutdown process (regardless of whether the EGUs on a common stack share all 

control devices or have some individual controls), all EGUs sharing the common stack should be exempt 

from numerical emission limits when any EGU is in startup or shutdown mode, the EPA disagrees, 

noting that, as described above, figures showing emissions data from EGUs sharing a common stack and 

in startup and shutdown mode with varying degrees of emissions control do not exhibit problematic 

conditions for other EGUs sharing the common stack but not in periods of startup or shutdown from 

showing compliance with the averaging period associated with the emissions limit. The EPA also 

believes that HAP emissions during periods of startup and shutdown are likely to be close to or lower 

than during other operating periods for the best performing EGUs and the EGUs complying with the 

final work practice requirements, contrary to the commenters’ implication that startup and shutdown 

emissions will necessarily lead to greater HAP emissions.

The EPA agrees with the commenter who states that perceived problems with the use of common stack 

monitoring could be avoided with use of monitoring systems on every individual boiler; the Agency also 

acknowledges that installation of individual EGU monitoring systems could be expensive and difficult; 

however the EPA reminds the commenter and others that they are required to provide appropriate 

accommodations for performance tests, as described in section 63.7(d)(1), whether from the common 

stack or individual stacks. The EPA also notes that in most cases, existing guidance provides

instructions for installing monitoring instruments in challenging locations.

Comment 88: Commenter 20420 suggests that the EPA should clarify the application of the startup and 

shutdown work practice standards to EGUs demonstrating compliance in accordance with 40 CFR 

63.10010(a)(2)(ii) in Table 3 to subpart UUUUU.

Response to Comment 88: As mentioned earlier, this final rule clarifies startup and shutdown work 

practice standards for EGUs that share a common stack.

 

10 See 40 CFR 63.6(e)(1)(i), which says that “...At all times, including periods of startup, shutdown, and 

malfunction, the owner or operator must operate and maintain any affected source, including associated 

air pollution control equipment and monitoring equipment, in a manner consistent with safety and good 

air pollution control practices for minimizing emissions...” 
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1.2.6 Allow site-specific standards

Summary of Comments Received Following November 30, 2012, Proposal

Comment 89: Commenters 20246, 20248, 20256, 20269, 20276, 20279, and 20288 ask that the EPA

allow EGUs the option of developing site-specific or unit-specific work practices that would apply 

during periods of startup and shutdown in order to take into consideration different boiler types, air 

pollution control equipment and other site- or unit-specific characteristics that would better reflect the 

diversity of EGU operations.

Commenters 20269 and 20279 note that creating SS plans is a time-consuming process and that it will 

be more efficient and cost-effective for some EGUs to follow the EPA’s proposed work practice 

standards. Commenters state however, many EGUs would require site-specific startup and shutdown 

procedures to ensure safe operating conditions, to comply with requirements established by other EPA 

rules, or to avoid equipment damage. Commenters ask that deviations from the site-specific SS plan (if 

allowed) not be considered a violation as long as “the applicable emissions limits are not exceeded and 

the EGU is operating with the intent of meeting the limit.”

Commenter 20288 states that work practice standards should reflect that each generating EGU is 

different in its construction, fuel, emissions controls and that the characteristics of startup and shutdown 

events vary greatly. Commenter recommends that separate work practice standards be developed for 

every affected EGU under various startup and shutdown scenarios, reflecting the capabilities of control 

equipment to operate safely and effectively during different phases of the startup and shutdown process. 

Commenter provides further notes regarding specific startup and shutdown work practices and that work 

practice standards should also recognize that EGUs must conduct periodic maintenance activities.

Commenter 20248 states that the EPA’s current definition (and proposed changes) does not solve the 

problem of how to account for emissions during startup and shutdown and presents compliance 

challenges. Commenter states that it has worked with many permitting agencies to develop startup and 

shutdown requirements in Title V permits and requests that the EPA modify the startup and shutdown 

work practice standard to enables EGU owners to rely on startup and shutdown plans in their Title V 

permits. Commenter states that this structure would allow EGU owners to work with their permitting 

agencies to develop a startup and shutdown exemption period that acknowledges challenges specific to 

each EGU in addition to having federally enforceable startup and shutdown requirements. According to 

commenter, the Proposal would result in instances where existing Title V permits and the MATS rule 

could conflict, and result in conflicting startup and shutdown compliance periods. To illustrate how Title 

V permit definitions of startup and shutdown can be different to accommodate unit-specific control 

equipment, commenter provides examples of startup language from current operating permits. 

Commenter 20248 states that the need for EGU-specific startup and shutdown language is particularly 

important for EGUs that cycle (in contrast to base-load EGUs) in order to avoid creating a situation 

where EGUs would be required to stay on-line out of merit and displacing more efficient EGUs to avoid 

multiple startups during a 30-day averaging period. Commenter 20248 states that the EPA has 

implemented a similar approach of EGU-specific plans under its existing CEMS regulation (40 CFR 

Part 75).
95

Commenter 20246 states that the EPA should allow affected sources to operate according to site-specific 

start-up and shut-down plans that are approved by designated authorities (state agencies). Commenter

said any start-up and shut-down requirement should enable the facility to freely generate and use 

electricity during start-up and shut-down consistent with equipment and manufacturer requirements and 

to allow operation according to start-up and shut-down plans which identify the proper firing of clean 

and primary fuels for minimizing emissions in a manner consistent with equipment and safety 

requirements.

Commenter 20279 states that the proposed requirement that EGUs start certain pollution control 

technology as expeditiously as possible’ after startup, whereas all other controls must start immediately 

illustrates the EPA’s limited recognition of operating constraints during startup and shutdown and 

failure to acknowledge the diverse operating requirements of EGUs subject to the MATS. Commenter

recommends that the EPA adopt additional compliance options that would supplement the proposed 

work practice standards for startup and shutdown and address the unique operating constraints facing 

certain EGUs.

Commenter 20279 states that to accommodate its unique operational constraints, each EGU has a plan 

for starting up safely in a manner that minimizes emissions, protects equipment, and complies with 

existing regulations. Commenter states that although the EPA’s proposed approach will address safety 

and operational concerns at some EGUs, it could lead to unnecessary safety risks and equipment damage 

if plant workers disregard existing plant procedures and start controls before it is safe to do so in order to 

avoid noncompliance.

Commenter 20408 suggests that startup and shutdown should be defined on a unit-by-unit basis in 

consultation with the state or local permitting authority. Commenter notes that this should be based on 

the type of boiler, the emission controls attached, and historical information on previous SS durations; 

this SS time or a set of operational criteria could then be included in the Title V operating permit along 

with recordkeeping and reporting requirements.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 90: Commenter 20392 states that it continues to believe and support a unit-specific approach 

that would be a part of the operating permit under which the EPA would have a decisional role in 

approving. Commenter maintains that the approach outlined in the June 25, 2013, notice of ending 

startup 3 hours after achieving 25 percent of nameplate capacity or 6 hours after the first generation of 

electricity would place some of its EGUs into violation situations that it would likely not be able to 

correct when there were unanticipated startup and shutdowns within the same averaging period due to 

EGU malfunctions. Commenter states that extending the time period to 4 and 12 hours would reduce its 

compliance risk, but would not necessarily address the issues that an EGU-specific plan would cover.

Commenter 20392 states that approach provided in the June 25, 2013, notice appears to be a surrogate 

for achieving an appropriate flue gas temperature at which the EGU and the emissions controls would be 

able to operate safely and effectively. Commenter believes that, as such, it would be more appropriate to 

base the end of startup on the achievement of a certain flue gas temperature needed to allow for the safe 

and effective operation of the EGU and the emission control equipment and that this type of approach 

would most effectively be implemented on a unit-specific basis considering the overall design and 
96

operation of the boiler, as-well-as the mix of pollution control equipment that has been determined 

appropriate and approved by the permitting authority. Commenter maintains that the imposition of a one 

size fits all requirement for the numerous differences in the operation of the many different types of 

EGUs in operation today does not provide a significant environmental benefit over allowing the 

permitting authority to develop/consider and approve a startup plan in the permit that would reduce 

emissions to the greatest extent practicable, while allowing the EGU to operate according to the good 

engineering practices that would provide for the safety of the plant personnel and the continued life of 

the EGU.

Commenter 20396 supports Commenter 20419’s comments to have an approach where an EGU elects 

either to follow the EPA’s definition of startup or to work with regulators to develop an individualized 

SS plan.

Commenters 20396, 20397, and 20428 prefer development of a unit-specific plan, and only as an 

alternative, support revised definitions of startup. 

Commenter 5840 states that ’its preferred solution is to establish unit-specific work practices that define 

the beginning of startup and the end of startup, with the practices and definitions submitted to and 

approved by the permitting authority. Commenter notes that it is its experience that there are necessary 

variations in startup procedures even among “identical” or similar supercritical EGUs based on specific 

design and equipment considerations and that startup procedures are typically developed based on the 

equipment at each EGU.

Commenter 20407 states that each individual EGU is unique in its standard protocols for completing a 

startup and that this uniqueness is derived from the type and manufacturer of the EGU, its controls, 

required auxiliary equipment, type of APCDs, and configuration of the APCDs. Commenter notes that, 

furthermore, each startup event for a given EGU is unique and poses its own set of challenges. 

Commenter does not believe that it is appropriate, given the large number of operational variables that 

can occur and affect a startup event, to establish a specified time limit to a startup event applicable to all 

EGIs as proposed in the reconsideration. Commenter believes that the most appropriate standard related 

to startup would be to require EGUs to develop a unit-specific Startup and Shutdown Plan. Commenter 

states that records should be kept to document adherence to the plan. Commenter states that as expressed 

previously, an EGU experiences significant economic losses while in a startup condition, and as such, 

there is no incentive to remain in startup mode. Commenter does not believe that it is appropriate or 

necessary to require that a unit-specific Startup and Shutdown Plan be approved by the local permitting 

authority. Commenter states that however, if the EPA chooses to implement startup and shutdown 

provisions through approval by a permitting authority, the EPA must formally propose guidance to 

ensure consistency in applying these provisions.

Commenter 20419 states that that the EPA should allow EGUs to either (1) elect to comply with the 

definitions of the end of startup as proposed in the EPA’s Proposed Reopening, or (2) determine the 

boundaries of startup in a SS plan based on manufacturer specifications or unit-specific considerations. 

Commenter urges the EPA to adopt both options for defining startup and shutdown. Commenter states

that creation of SS plans is a time-consuming process, and some EGUs will prefer to use the EPA’s 

definition for the end of startup. Commenter states that but for EGUs where site-specific considerations 

prohibit placing control equipment in service in a timeframe that would meet the proposed definition of 
97

the end of startup, SS plans would provide these EGUs with the flexibility necessary to implement 

efficient and safe operating practices without risking noncompliance with the MATS. As an alternative, 

commenter reiterated its support in its prior comments for the EPA’s proposal in the Proposed 

Reconsideration Rule to allow EGUs to start limestone injection, dry scrubbers, SNCRs, and SCRs 

when it is practicable to do so. However, as noted in commenter’s prior comments, the EPA should 

provide that all APCDs begin operating when it is practicable to do so.

Commenter 20419 states that as explained in EPA-HQ-OAR-2009-0234-20269, for EGUs that select the 

second option, SS plans would allow owners and operators to determine when, under the MATS, startup 

ends based on parameters that are easily monitored at that EGU. Commenter states that these parameters 

could be based on requirements in other rules to which EGUs are already subject. Commenter states that 

for example, EGUs subject to 40 CFR Part 75, Appendix A (which governs continuous emission 

monitoring for affected EGUs under the Acid Rain Program) already are required to define the EGU’s 

ranges of operation and normal load. Commenter states that startup for such EGUs could easily be based 

on these ranges of operation. Commenter notes other EGUs may need to designate the end of startup as 

the point in time when the EGU reaches a certain temperature so that air pollution control equipment can 

be safely and effectively operated.

Commenter 20419 states that allowing EGUs the option to develop SS plans would ensure that EGUs 

can operate safely and efficiently without jeopardizing compliance with the MATS. Commenter states

that this option also would avoid potential conflicts between the MATS and other applicable 

requirements, would regulate SS more efficiently than applying multiple, overlapping SS requirements, 

and would reduce unnecessary administrative burdens on regulated sources. For these reasons, 

Commenter urges the EPA to allow EGUs to elect to either follow the definition of the end of startup as 

proposed in the Proposed Reopening, or to follow an individualized SS plan.

Commenter 20417 suggests that the EPA allow EGUs two compliance options – they can either (1) elect 

to comply with a definition of the end of startup similar to that described by the EPA or (2) determine 

their individual boundaries of startup in a SS plan based on site-specific considerations. Commenter 

states that, creation of SS plans is a time-consuming process, and some EGUs may prefer to use the 

MATS Rule definition for the end of startup and will be able to do so without compromising safety or 

reliability. Commenter goes on to say, but for EGUs where site-specific considerations require the use of 

a different definition, SS plans would provide these EGUs with the flexibility necessary to implement 

efficient and safe operating practices without risking noncompliance with the MATS.

Response to Comments 89 and 90: The EPA is finalizing definitions and work practice standards for 

startup and shutdown periods based on the performance of the best performing sources during those 

periods. The EPA does not believe individual startup and shutdown plans, essentially allowing sources 

to continue their current approach without change, are consistent with the statute. Regarding the 

commenter’s suggestion to establish a process by which an EGU may petition for the establishment of a 

unit-specific startup period on a case-by-case basis to ensure the efficient and safe operation of the 

APCD, the EPA notes that such a process for developing an alternative emissions limitation already 

exists in the general provisions of EPA’s Part 63 regulations. See 40 CFR 63.6(g). In addition, we are 

including provisions related to the petition process at 40 CFR 63.10030.
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1.2.7 Title V, state, or local permitting

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 91: Commenter 20401 requests the Reopened Rule be revised to allow EGUs to develop their 

own site-specific work practice standards for startup based on the manufacturer’s specifications for the 

AQC equipment at each site, and states that that startup should be defined on a site-specific basis that 

rests on the recommended specifications and requirements for the AQC equipment associated with the 

EGU, and is submitted and approved by the permitting authority and placed in the facility’s Title V 

permit. Commenter maintains that EGUs already have considerable incentive to develop efficient startup 

plans since it is economical for EGUs to end startup quickly and reach stable operation with efficient 

heat rates. Commenter would, as an alternative, support the option offered by other commenters that 

startup ends 12 hours after first electricity generation.

Commenter 5833 suggests that the startup period be defined by “work practices” rather than a fixed time 

period of several hours and indicates that these work practices could be developed for individual EGUs 

and written into permits issued by the facility’s state regulatory agency. If this approach is not 

acceptable, commenter supports the approach provided by Commenter 20428.

Commenter 5840 states that work practices for periods of startup and terms such as the “end of startup”

should be defined on an individual basis for each EGU, with the definition submitted to and approved by 

the permitting authority.

Commenter 20390 states that depending on the APCD installed and permitted, each plant requires 

review to define startup and shutdown operating conditions and determine if improvements can be made 

to the existing design to minimize emissions during startup and shutdown.

Commenter 20403 states that the timeframe of each specific step needed for start-up can be addressed as 

part of the Title V permit, where the permittee can provide the State Regulatory Authority the basic 

procedures with anticipated time frames when startup would end. 

Commenter 20393 states that if the EPA decides to establish a bright line test, commenter urges the EPA

to also establish a process in which an electric utility may petition the relevant permitting authority to 

establish a unit-specific startup period on a case-by-case basis to ensure the efficient and safe operation 

of the APCD. Commenter states that this alternative approach, the final MATS regulations would 

authorize the permitting authority to set a different end of the startup period for an APCD at a particular 

coal-fueled EGU based on specific design and operating parameters at the EGU.

Commenters 20395, 20396, 20423, 20425, 20428, and 20429 agree with Commenter 20428’s earlier 

comment that the optimal way for the EPA to address startup is to allow Title V permitting authorities to 

approve unit-specific startup plans for each EGU. Commenter 20425 states that startup definition should 

be determined by the permitting agency on a unit-by-unit basis due to the complexity and variances 

between different EGU. Commenter 20429 notes that startup periods are dependent on specific EGU 

designs and specific EGU equipment conditions during the startup and maintains that the EPA’s generic 

“one size fits all” approach based on averages of Clean Air Markets Division (CAMD) SO2 and NOx 
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data for hundreds of EGUs is not the best approach to ensure startup ends when air pollution controls 

may be placed in service and functioning.

Commenters 5833 and 20393 suggest that the EPA adopt a more flexible approach that allows state 

permitting authorities to define the end of startup for the respective coal fueled EGU’s in their 

jurisdiction on a case-by-case basis. Commenters state that EGUs of different sizes, age, and control 

device configurations will have different startup times in accordance to each EGU’s operational design, 

manufacturer’s operating specifications, and safety requirements and that these requirements would be 

best addressed on a case by case basis instead of a blanket definition of the end of startup. Commenter 

5833 expresses concern that the EPA is trying to establish a “time-certain” requirement as to when coal 

fueled EGUs must begin to operate APCDs under a wide range of design parameters and operating 

conditions.

Commenter 20390 urged the EPA to be consistent with the established permit requirements for many 

sources in its definition of startup and shutdown. Commenter states that most state and local air permits 

and many consent decrees for new and existing sources exempt startup and shutdown periods, and that 

this has been the trend for over 10 years. Commenter states the exemptions typically include a fixed 

period of time or when the source is able to get APCD in operation and stable. Commenter states the 

period of time is typically adjusted for type of startup (e.g., hot, cold) due to restrictions on the turbine 

or boiler in heat ramp and temperature.

Commenter 20416 supports Commenter 20396’s comments and agrees with the EPA’s recent efforts to 

establish a safe and effective work practice standard for startup and shutdown periods. Commenter states

that startup periods involve the co-firing of startup and primary fuels prior to engaging APCDs; 

therefore, commenter recommends that the EPA allow utilities and delegated permitting authorities the 

flexibility of establishing unit-specific practices for SS periods. Commenter states that the EPA should 

allow EGU’s to implement procedures specific to manufacturer specifications which will ensure 

optimum and safe operations during periods of startup and shutdown.

Response to Comment 91: The EPA is finalizing definitions and work practice standards for startup 

and shutdown periods based on the performance of the best performing sources during those periods.

The commenters advocate for site specific work practice plans, but the commenters do not explain how 

their proposed approach complies with the requirements of CAA section 112(h). For these reasons, we 

are not adopting the alternative approaches suggested in these comments. Regarding the commenter’s 

suggestion to establish a process by which an EGU may petition for the establishment of a unit-specific 

startup period on a case-by-case basis to ensure the efficient and safe operation of the APCD, as noted in 

the response to comments 89 and 90 above, such a process for developing an alternative emissions 

limitation already exists in the Part 63 General Provisions.

1.2.8 Petition the Administrator

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 92: Commenter 20399 appreciates the effort and thoroughness of the EPA’s Startup TSD and 

agrees with the EPA that:
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on average, all types of EGUs...can begin controlling SO2 and NOx emissions 3 hours or 

less after reaching 25 percent of nameplate capacity or 6 hours or less following the start 

of electricity generation units can ending the startup exemption 3 hours after a unit 

reaches 25 percent nameplate capacity or 6 hours after electricity generation.

Commenter 20399 states that the EPA’s use of “on average” makes it apparent that the EPA recognizes 

the ability to control SO2 and NOx within the specified time frame will not apply to every EGU. 

Commenter states that accordingly, it requests that the EPA consider amending the definition to enable 

individual generators to petition the Administrator for alternate language that would (1) define startup or

shutdown (or both) for a particular source, and (2) provide an alternative compliance pathway for EGUs 

with unique conditions and operating concerns. Commenter states that requesting generators should 

have the ability to petition the Administrator through development of an SSM plan according to 40 CFR 

63.6(e)(3)(i). Commenter states that this process would give EGUs with control devices that take longer 

to bring online the same exemption given EGUs with control devices that can be brought online in less 

time.

Commenter 20399 states that the EPA’s analysis demonstrates that not all APCDs are capable of 

reaching MATS compliance within the proposed startup window. Commenter states that according to 

the EPA’s data, some dry FGD EGUs are at twice the SO2 rate for the HCl surrogate limit as the 

proposed startup period ends. Commenter states that this rate may not be an issue if a particular EGU

has limited startups in a month, but for a cycling EGU this rate could become a considerable compliance 

hurdle. Commenter states that the EPA should avoid creating a situation where EGUs would be incented 

to stay on-line out of merit, displacing more efficient EGUs in order to avoid multiple startups during a 

30-day averaging period.

Response to Comment 92: The EPA is finalizing definitions and work practice standards for startup 

and shutdown periods based on the performance of the best performing sources during those periods.

The commenter’s characterization of the work practice as an exemption is misplaced as discussed above.

To the extent the commenters’ units are unable to achieve the final work practice standard, the EGU will 

have to be modified and/or the clean fuel capacity increased, as appropriate. If necessary, the EGU 

owner or operator may seek an alternative emission limitation consistent with the requirements of 40 

CFR 63.6(g).

1.2.9 Flexibility to reflect equipment variability

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 93: Commenter 20391 states that in addition to the use of a presumptive definition, the EPA 

should provide flexibility for compliance during SS through an alternative option that recognizes the 

diverse operating characteristics and constraints of EGUs. Commenter states that although the concept 

of a presumptive (or default) definition for the end of startup may serve to provide many EGUs the time

needed to achieve operating benchmarks, it may not be readily applicable to all boilers, which have a 

wide variety of operating modes. Commenter states that the EPA needs to recognize/account for 

extenuating circumstances when EGUs may fall out of these categorical definitions (startup after a major 

turbine outage, for example) and provide for alternative options. Commenter states that, therefore, in 

order to fully recognize the diverse operating characteristics and operational constraints across EGU’s 
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subject to the Utility MATS rule, the EPA should provide flexibility by allowing affected EGUs the 

following options:

(1) Comply with the work practice standards using a presumptive definition (as a default 

option). As noted above, the EPA should adopt the definition suggested by Commenter 

20428 (i.e., “the 4/12 test”); or

(2) Allow EGUs to develop individual SS plans, subject to approval by the appropriate 

permitting authority, containing site-specific work practice standards based on 

manufacturer specifications or based on the “default” approach with alternative 

timeframes. This would allow source operators to determine when startup and shutdown 

begins based on parameters that are monitored on a given EGU and could be based on 

requirements in other rules to which the EGU is already subject. These specifications 

define startup and shutdown using factors more than load, such as the completion of 

specific procedures and run time.

Commenter 20391 states that this approach would allow affected EGUs the option of following 

established work practice standards where it is technically feasible, efficient and cost-effective to do so 

and would provide for necessary regulatory flexibility for EGUs with site-specific, unique operating 

constraints. Commenter states that this would better assure that each EGU has a workable SS plan that 

adequately addresses safe operations, protects equipment, minimizes emissions and complies with 

existing regulations.

Commenter 20390 states that boiler startup and shutdown are critical periods for the operations of 

APCDs and it does not believe that there is one set rule that can cover all the diverse designed power 

plants that exist today. Commenter maintains that there are some external issues that it is not sure some 

people will recognize and alleges that plants try to synch as fast as possible based on equipment 

constraints. Commenter indicates that due to current grid stability, ISOs and transmission management 

have very strict requirements for ramp rates and synch schedules. Commenter notes that the North 

American Electric Reliability Corporation (NERC) and the Federal Energy Regulatory Commission 

(FERC) are involved to ensure a stable grid, which has been exacerbated by renewable s and low dark 

spreads. 

Commenter 20390 recommends a work practice procedure to determine when startup and shutdown start 

the clock for compliance – each plant is so unique that the process has to be designed for each plant. 

Commenter states that although this makes enforcement more difficult for the EPA, a work practice 

process with guidelines can be developed by industry, the EPA, equipment manufacturers, and 

environmentalists. 

Commenter 20390 states that periods of operation, especially for boiler startup, are characterized by 

rapid transient changes in flue gas composition, quantity, temperature, and moisture conditions. 

Commenter notes that the EPA training manuals for FF and ESPs indicate improper startup and 

shutdown can not only damage the equipment but also result in performance degradation. Commenter 

states the problems are further aggravated with multiple APCDs, including SNCR, SCR, dry sorbent 

injection (DSI), PAC, scrubber (CDS, SDA, wet FGD), ESP, and/or FF. Commenter states that for 

startup and shutdown, the APCD cannot be viewed as single stand-alone entities but must be viewed as 
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an integrated APCD system with proper operation dependent on boiler flue gas characteristics and 

proper operation of the APCD.

Commenter 20390 states that the EPA should establish a database of startup and shutdown emissions to 

better characterize this issue. Commenter states the database should identify which APCD are in 

operation during those periods.

Commenter 20409 believes a more appropriate treatment of the startup would recognize the inherent 

differences between EGU designs and configurations that result in non-uniform startup durations. 

Commenter states that in fact, even individual EGU startup durations can vary considerably. Therefore, 

a more optimal approach would recognize the variability in startup durations defined by individual EGU

characteristics, and based EGU startup requirements on equipment manufacturers, vendor specifications, 

or similar technical considerations that could be included in an EGU’s Title V permit for example.

Commenter 20397 recommends the EPA include startup and shutdown definitions that account for 

distinctions between both the EGU sources and their APCDs. Commenter states that the definitions of 

both the source and APCD will dictate when startup and shutdown periods begin and end, such that 

compliance with the emission limit, which is based on one-time full load steady-state condition, better 

match conditions used to set the limit. Commenter states although this may make compliance plans for 

individual EGUs more complicated, owners and operators will be better able to assure compliance. 

Commenter notes the EPA could request monitoring data (over time), because it is collected at all times, 

and evaluate whether there are excess emissions and address those conditions on a case-by-case basis.

Comment 94: Commenter 20415 shares the concerns raised by other commenters and supports defining 

the end of startup with as much flexibility as possible, to account for the wide range of operational 

characteristics among boilers, emissions control systems and types and availability of “clean” ignition 

fuels. Commenter states that the highest degree of flexibility would be provided by the EPA addressing 

the wide variations among boilers by revising the startup definition to allow facilities to determine the 

minimum stable operating load with emissions controls at stable operating condition on a unit-specific 

basis and include the minimum stable operating load and the proper procedures to follow during startup 

and shutdown in a site-specific plan. Commenter states that establishment of the minimum stable 

operating load on a site-specific basis is analogous to setting other boiler and control device operating 

parameter limits on a site-specific basis, which the EPA does routinely in the Boiler MACT rules.

Response to Comments 93 and 94: The EPA is finalizing definitions and work practice standards for 

startup and shutdown periods based on the performance of the best performing sources during those 

periods. The commenters appear to advocate for site specific work practice plans, but the commenters 

do not explain how their proposed approaches comply with the requirements of CAA section 112(h). For 

these reasons, we are not adopting the alternative approaches suggested in these comments. 

Furthermore, these and other commenters make assertions that the work practice may not be feasible for 

all types of units, but they fail to provide sufficient information and data to support their assertions as 

they relate to any specific EGU or aspect of the work practice. The EPA maintains that sources can 

make any number of physical (e.g., modify startup burners or increase clean fuel capacity) and

operational (e.g., combusting clean fuels alone for a longer period to warm the EGU or pre-coat bags to 

prevent blinding) changes at their facilities to comply with the final rule.
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As described above and in figures submitted by one commenter, EGUs sharing common stacks do not 

appear to have trouble meeting the emission limits, especially when the averaging period is considered, 

during any combination of operating conditions (e.g., periods of startup, shutdown, control device 

startup, control device shutdown, or normal operation).

11 Nonetheless, for those operators of EGUs 

sharing common stacks who choose not to monitor each EGU individually and who choose to seek an 

alternative compliance assurance method, the general provisions at 40 CFR 63.7(f) (shown below) 

provide the requirements for such requests.

(f) Use of an alternative test method—

(1) General. Until authorized to use an intermediate or major change or alternative to a 

test method, the owner or operator of an affected source remains subject to the 

requirements of this section and the relevant standard.

(2) The owner or operator of an affected source required to do performance testing by a 

relevant standard may use an alternative test method from that specified in the standard 

provided that the owner or operator—

(i) Notifies the Administrator of his or her intention to use an alternative test method at 

least 60 days before the performance test is scheduled to begin;

(ii) Uses Method 301 in appendix A of this part to validate the alternative test method. 

This may include the use of specific procedures of Method 301 if use of such procedures 

are sufficient to validate the alternative test method; and

(iii) Submits the results of the Method 301 validation process along with the notification 

of intention and the justification for not using the specified test method. The owner or 

operator may submit the information required in this paragraph well in advance of the 

deadline specified in paragraph (f)(2)(i) of this section to ensure a timely review by the 

Administrator in order to meet the performance test date specified in this section or the 

relevant standard.

(3) The Administrator will determine whether the owner or operator’s validation of the 

proposed alternative test method is adequate and issue an approval or disapproval of the 

alternative test method. If the owner or operator intends to demonstrate compliance by 

using an alternative to any test method specified in the relevant standard, the owner or 

operator is authorized to conduct the performance test using an alternative test method 

after the Administrator approves the use of the alternative method. However, the owner 

or operator is authorized to conduct the performance test using an alternative method in 

the absence of notification of approval/disapproval 45 days after submission of the 

request to use an alternative method and the request satisfies the requirements in 

paragraph (f)(2) of this section. The owner or operator is authorized to conduct the 

performance test within 60 calendar days after he/she is authorized to demonstrate 

compliance using an alternative test method. Notwithstanding the requirements in the 

preceding three sentences, the owner or operator may proceed to conduct the 

performance test as required in this section (without the Administrator’s prior approval of 

the site-specific test plan) if he/she subsequently chooses to use the specified testing and 

monitoring methods instead of an alternative.

 

11 See Figures 1, 2, 3, 6, 8, and 9 from Attachment I and the Figure from Attachment V from 

Commenter 20428.
104

(4) If the Administrator finds reasonable grounds to dispute the results obtained by an 

alternative test method for the purposes of demonstrating compliance with a relevant 

standard, the Administrator may require the use of a test method specified in a relevant 

standard.

(5) If the owner or operator uses an alternative test method for an affected source during a 

required performance test, the owner or operator of such source shall continue to use the 

alternative test method for subsequent performance tests at that affected source until he or 

she receives approval from the Administrator to use another test method as allowed under 

§ 63.7(f).

(6) Neither the validation and approval process nor the failure to validate an alternative 

test method shall abrogate the owner or operator’s responsibility to comply with the 

requirements of this part.

Comment 95: Commenter 20419 states that the definitions of hot, warm, and cold start-ups must be 

made on a unit-specific basis. Commenter disagrees with the EPA’s definitions of hot, warm, and cold 

start-ups in the Startup TSD. Commenter states that these definitions lack support in EPA-HQ-OAR2009-0234-20380 and do not accurately describe startups in the real world. Commenter states that the 

definitions of hot, warm, and cold startup vary from EGU to EGU. Commenter states that there are 

numerous factors that affect how quickly a boiler cools off, and utilizing a “one-size-fits-all” definition 

makes little sense. Commenter states that for example, a boiler in Texas will cool off much more slowly 

in July than in December, and a boiler in Wisconsin in January will cool off much quicker than a boiler 

in Texas in January. Commenter states that the EPA’s definitions are clearly inappropriate, as 

demonstrated by discrepancies in the times for hot, warm, and cold starts of a commenter’s member’

plant in Wisconsin using the plant’s definitions, the EPA’s definitions in the Startup TSD, and the 

definitions in the cited docket entry. Commenter concludes hot, warm, and cold starts must be defined 

on a unit-by-unit basis based on equipment temperature instead of hours offline.

Response to Comment 95: The commenter is incorrect in suggesting that the EPA is required to define 

the identified terms in a manner consistent with its perspective. More importantly, the EPA maintains 

that EGUs can start up on clean fuels no matter whether the EGU is cold, warm, or hot, and then bring 

the EGU up to the necessary temperature before beginning electricity generation and combustion of coal 

or oil. The commenters do not provide information that causes us to question this conclusion for the vast 

majority of EGUs as currently constructed, and we further believe that most of the remaining EGUs will 

be able to make changes at the facility that will allow the EGUs to comply with the final rule (e.g.,

increasing clean fuel capacity and/or reconfiguring the ducting or clean fuel burners to allow the EGUs 

to be properly warmed on clean fuels alone).

Comment 96: Commenter 20423 states that startup periods can vary by season and ambient 

temperature. Commenter states that, for example, startup in the winter in North Dakota when 

temperatures can be lower than -20 °F can take longer for equipment, including the PM control systems, 

to heat up to above acid dew point.

Commenter 20423 states that, as noted by the EPA, the normal progress of startup activities may involve 

the cessation of fuel combustion following the initial combustion of ignition or startup fuel. Commenter 

states that these interruptions may include planned multiple stop/starts of the combustion process, and 
105

unplanned but nevertheless necessary cessations in the same combustion process. Commenter states that 

in its experience these interruptions range in duration from a few hours to multiple days.

Commenter 20423 states that the EPA Startup TSD focuses on “normal,” or average, startups. 

Commenter states that the analysis fails to capture the unpredictability and inherent variability in how 

any given EGU starts up. Commenter states that for any owner/operator, the goal of startup is to bring an

EGU up to steady-state operation as quickly as can be safely done so that the EGU efficiently generates 

electricity and controls emissions as soon as possible. Commenter states that startups can vary for each 

given EGU based on factors including the length of time the EGU has been down, whether there are 

equipment malfunctions, etc. Commenter believes characterization of startups as “normal” suggests that 

any given EGU’s startup is a predictable and consistent event, which is not the case.

Response to Comment 96: Responses to these comments can be found above in response to comment 

95. In addition, we do not agree with commenter’s suggestion that the EPA must account for the 

variability of all EGUs. For example, when defining the end of startup, the EPA looked at the 

performance of the best performing sources using the metric we developed. Because we have data on all 

startup events at the EGUs with the relevant data, we maintain that it would arguably be reasonable to 

include no additional variability, but, to ensure a reasonable time for the end of startup in the final rule, 

we also determined it was reasonable to round the average time up to 4 hours. We looked at all startups 

during a 2-year period, including those that were subsequently interrupted (see Revised TSD).

Comment 97: Commenters 5834 and 5840 state that during startup the work practice standards must 

allow for a phasing in of the operation of ESPs, as well as other APCD, consistent with safe and 

technically feasible operations. Commenter 5834 explains that ACI controls for Hg are not effective 

until ESPs are engaged. Commenter 5840 states that site specific work plans can incorporate procedures 

that identify the points when specific APCDs are placed in service. Commenter notes that these sitespecific operating procedures could include compliance with boiler and APCD manufacturer’s operating 

procedures or the EGU’s written Standard Operating Procedures manual during startup and shutdown; 

they could also include requiring operation in a manner consistent with those procedures to minimize 

emissions including starting APCDs as soon as practical. Commenter maintains that such standards 

could include a reasonable period of time allowed for a startup considering the limitations inherent in 

starting and balancing operational parameters associated with complex equipment.

Response to Comment 97: The EPA is finalizing definitions and work practice standards for startup 

and shutdown periods based on the performance of the best performing sources during those periods. 

The commenters advocate for site specific work practice plans, but the commenters do not explain how 

their proposed approach complies with the requirements of CAA section 112(h). For these reasons, we 

are not adopting the alternative approaches suggested in these comments. Regarding the commenter’s 

suggestion to establish a process by which an electric utility may petition for the establishment of a unitspecific startup period on a case-by-case basis to ensure the efficient and safe operation of the APCD, as 

noted in the response to comments 89 and 90 above, such a process for developing an alternative 

emissions limitation already exists in the Part 63 General Provisions. We address the operation of ESPs 

elsewhere in this document.

Comment 98: Commenter 5840 states that its coal fleet is comprised of 11 supercritical and two FBC 

EGUs. These EGUs typically continue to burn startup fuel after beginning to generate electricity for heat 
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production and flame stability purposes. Commenter maintains that emission controls may or may not be 

in service at this time due to good operational practices, manufacturer recommendations, permit 

conditions, and/or safety considerations; those APCDs that are engaged are not operating at design 

conditions until control equipment-specific temperature ranges are achieved. Commenter alleges that 

supercritical EGUs are unstable when operating in subcritical mode and owner/operators are, therefore, 

incented to safely move the EGU to supercritical operation as quickly as possible; operators are also 

incentivized to place APCD in service as quickly and safely as possible.

Response to Comment 98: The EPA acknowledges that some APCDs may not be operating at design 

conditions until after the time defined to be the end of startup. However, as noted elsewhere in this 

document, the EPA believes that its analysis of the startup practices of the top performing 12 percent of 

EGUs, which included all types of EGUs, and its final definition of “startup” adequately balances 

commenters’ concerns with the requirements of CAA section 112. The EPA notes that the goal of the 

analysis was to identify the approximate time it took, on average, to initiate operation of APCDs by the 

top performing 12 percent of EGUs for the purpose of defining the end of startup. The goal was not to 

seek the time it took for APCDs at all EGUs to become fully operational, as that would not be consistent 

with CAA section 112(h).

2.0 CLEAN FUELS

Summary of Comments Received Following November 30, 2012, Proposal

Comment 99: Commenter 20288 agreed that companies should use clean fuels for startup and shutdown 

to the extent possible and provided those fuels are available at that site.

Response to Comment 99: This comment requires no response.

Comment 100: Commenter 20305 asks that the EPA clarify that it is not proposing changes to the 

requirement that sources burn clean fuels during startup and shutdown. Commenter notes that in the 

Reconsideration, the EPA is “proposing to require EGU source owners and operators, when firing coal, 

solid oil derived fuel, or residual oil in the EGU during startup or shutdown, to vent emissions to the 

main stack(s) and operate all control devices necessary to meet the operating standards that apply at all 

other times under the final rule...” (emphasis added). Commenter observes that this reference to venting 

emissions when “firing coal” during startup or shutdown suggests that EGUs can burn coal during 

startup and shutdown. 

Commenter 20305 notes that industry is required to provide emission estimates during startup and 

shutdown in its SSM permit applications and that data show that requiring EGUs to burn clean fuels 

during periods of startup and shutdown would result in significant emission reductions. Commenter

provides copies of permit applications with startup and shutdown emissions. Commenter notes that the 

permit applicants projected emissions based on assumptions about coal feed rate during startup and 

shutdown, and applying AP 42 factors to estimate emissions during uncontrolled combustion of coal. 

Commenter states that these permit applications support the use of clean fuels during startup and 

shutdown.
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Comment 101: Commenters 20246, 20248, 20252, 20254, 20269, 20272, 20283, 20287, 20303, and 

20321 state that they are not able to complete startup on clean fuels alone.

Commenter 20246 states that in some cases, large boilers may not have sufficient clean fuel firing 

capacity to fully meet boiler start-up needs.

Commenter 20248 states that the proposed changes to the existing requirements are problematic for 

EGUs that do not have the physical capability or adequate fuel supply to complete “startup” as defined 

by the EPA solely on a clean fuel and that EGUs that need to add coal or heavy oil with “clean fuel” in 

order to generate electricity for sale or make useful thermal energy simply will not be able to comply 

with the requirement to only use clean fuels during startup. Commenter states that to satisfy this 

arbitrary work practice standard, many EGUs would need to modify their oil burner configurations, 

install additional piping and pumps, and/or increase storage capacity for clean fuels. Commenter states

in light of the relatively small differences between HAP emissions related to heavy oil when compared 

to emissions related to clean fuel, these EGUs should not be required to absorb the additional capital 

expense to modify its SS process and additional operating expenses for startup, and modification may 

not always be economically justifiable and/or possible. Commenter asks that the EPA clarify that it did 

not intend to subject limited use liquid oil-fired EGUs to the startup and shutdown work practice 

standards, because these EGUs are not subject to numerical standards and therefore do not require a 

defined emission limit exemption during these periods of operation. Commenter suggests that the EPA 

maintain the clean fuel requirement in the finalized MATS rule with modification to reflect the revised 

list of clean fuels. Commenter recommends that the existing Table 3 (FR 77 9493) be revised as follows:

“You must operate all CMS during startup. Startup means either the first-ever firing of 

fuel in a boiler for the purpose of producing electricity, or the firing of fuel in a boiler 

after a shutdown event for any purpose. Startup ends when any of the steam from the 

boiler is used to generate electricity for sale over the grid or for any other purpose 

(including on site use). For startup of a unit, you must use clean fuels, either natural gas 

or distillate or a combination of clean fuels for ignition.”

Commenter 20248 states that, alternatively, if the EPA requires that EGUs only use clean fuels for the 

entire startup process, the EPA should revise the definition of “startup” to provide the option for EGUs 

to voluntarily end the startup emissions exemption period. Commenter states that this option would 

allow a source to end its startup when a fuel not meeting the “clean fuel” definition is initially 

introduced. Commenter recommends specific revised definitional language for “startup.”

Commenter 20254 indicates that the proposed work practice requirement that baghouses and some other 

APCDs must be in use as soon as any coal is burned in the boiler is neither realistic nor consistent with 

equipment manufacturers’ specified operating procedures. Commenter notes that this is especially the 

case for many older or smaller coal-fired boilers that are not able to achieve the correct temperature for 

the operation of a baghouse while using the igniter to burn a “clean fuel” (e.g., natural gas) as is required 

under the proposed MATS startup work practices standards. Commenter states that the compliance 

challenges stem from the fact that in many instances the igniter offers only a low heating value, 

especially on older and smaller EGUs, and therefore it cannot serve a heating function well over long 

periods of time; it would require a large number of additional hours in order to reach the proper startup 

temperatures if an EGU is solely using the igniter and a clean fuel. In the case of two of commenter’s 
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coal-fired EGUs, the existing igniters used for startup of the EGUs are not of sufficient capacity to bring 

the baghouse to recommended operating temperature. In addition, commenter states that it is impractical 

to require that the igniter fuel, here natural gas, be the only fuel used to get to boiler up to the correct 

temperature as this would require a large amount of natural gas, and there are serious natural gas supply 

concerns for these EGUs because the natural gas pipeline capacity has limited supply. Commenter

indicates that the EPA suggests in technical guidance that there are no constraints on running a boiler on 

clean fuels for a longer period of time in order to reach the correct temperatures, and therefore that 

sources will be able to delay the use of baghouses until that time. However, commenter believes it is not 

technically feasible to use a small igniter burning a limited supply of natural gas for a long enough 

period to have the boiler reach the correct temperature without burning any coal.

Commenter 20269 states that FF are similarly impacted by flue gas temperature and, as a result, certain 

designs cannot be operated until startup is complete. One of commenter’s members owns a coal-fired 

EGU that operates a baghouse for PM control during periods of normal operation. The flue gas must 

reach a certain minimum temperature before the baghouse is put into service to prevent acid corrosion 

from damaging the baghouse and resulting in its failure. Commenter notes that this facility starts up on 

natural gas, but lacks sufficient natural gas capacity for the EGU to complete the startup process; due to 

this limitation, coal must be fired about 30 minutes into the startup process but before startup is 

complete, allowing the flue gas to reach the necessary temperature for the operation of the baghouse.

Commenter 20272 states that many utility boilers will simply not be able to generate sufficient heat to 

achieve the manufacturer’s recommended minimum temperature levels for the ESP while burning only 

oil or gas startup fuels. Commenter notes that one reason for this is that the oil or gas igniters for coalfired EGUs were never designed to preheat the ESP plates without the combustion of coal. Commenter

indicates that to put it in other words, these boilers – which tend to be the older design coal-fired EGUs 

– are equipped with igniters that were meant solely to light the fuel, not to provide sufficient heat to 

warm up the ESP hardware to the manufacturer’s specified temperature levels. Commenter alleges that

to the EPA’s claims, these EGUs cannot generate adequate heat to energize the ESP even if they 

combust only oil or gas startup fuel for an extended period of time.

Commenter 20283 states that many coal-fueled EGUs must combust coal along with oil or gas during 

startup in order for the ESP to achieve adequate temperatures for the proper and safe operation of the 

control equipment. Commenter notes that without the combustion of coal, many utility boilers will 

simply not be able to generate sufficient heat to achieve the manufacturer’s recommended minimum 

temperature levels for the ESP while burning only oil or gas startup fuels.

Commenter 20287 states that the proposed revisions appear to require clean fuels not only for ignition 

(as the final MATS rule required) but throughout the startup period. Commenter notes that, like many 

other facilities, it uses distillate fuel exclusively to ignite its three boilers and thereafter to supplement its 

primary fuel until startup is complete. Commenter’s station is not designed to exclusively fire distillate 

to the point that the EGUs produce electricity or useful thermal energy, which is how the EPA proposes 

to define the end of “startup.” Commenter notes that it must introduce coal to complete startup and to 

increase flue gas temperatures to the level at which its ACPDs are effective. Commenter states that the 

cost to retrofit the EGUs to enable them fire exclusively clean fuel through startup would be substantial 

and far outweigh any marginal benefit. Commenter states that the best approach and the only one 

supported by the record is for the EPA to clarify in Table 3 in the final rule that clean fuels need only be 
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used for ignition of an EGU and that other fuels can be blended into the fuel mix after ignition but 

before the end of startup without violating the work practice standards.

Commenter 20287 states that if the EPA requires existing EGUs to use clean fuels beyond ignition, it 

recommends that the EPA not mandate the exclusive use but rather the use permissible with the 

facility’s existing fuel capabilities. Alternatively, commenter suggests the EPA could revise the part of 

the definition of startup that defines the end of startup to include “...and 18 CFR 292.202(c)), or when 

fuels other than clean fuels are first used, whichever is earlier.” This would allow facilities to avoid 

being in violation of the rule’s work practice standards simply because they have insufficient clean fuel 

firing capacity.

Commenter 20303 states that the design of its EGU does not include large oil guns but is designed with 

oil igniters (firing #2 fuel oil) that do not permit the EGU to be synchronized (generate electricity) prior 

to starting a coal pulverizer.

Commenter 20321 states that the proposed work practice standard to combust clean fuels during periods 

of startup and shutdown is not feasible for commenter’s EGUs. Commenter explains that because of the 

size of the natural gas igniters, natural gas can produce enough steam to start or “roll” the turbine in its

EGUs, but coal-firing must begin immediately because large steam generators are unstable at such very 

low loads. Commenter states that the EGUs would require reconfigured igniters, piping and valves, and 

additional natural gas transmission capacity. Commenter states that these expensive changes would have 

little environmental benefit, as the added natural gas firing would only be used for a short time by the 

EGUs, very few times during a typical year.

Commenter 20252 states that the EPA should clarify in the regulation that the clean fuel required for 

startup does not foreclose the burning of solid fuel during startup, as long as emission controls are 

engaged as set forth in the work practice standard. Commenter notes that the preamble mentions firing 

coal, solid oil-derived fuel, or residual oil in the EGU during startup or shutdown, but the regulatory text 

does not reflect that understanding. Commenter states that it is not operationally possible for coal-fired 

stoker boilers and possibly other solid fuel boilers to burn only clean fuels during the entire startup 

period. Commenter states that its coal-fired stoker boiler transitions from offline to fully operational, 

using clean fuel initially to ignite some coal and then slowly the remaining coal is ignited and builds 

enough heat for the boiler to be fully operational. Commenter asks for clarification to recognize that a 

transition to solid fuel is an integral and essential step in the startup process and suggests that following 

alternative language in Table 3 of the rule:

To initiate For startup of an EGU, you must use one or a combination of the following 

clean fuels: natural gas, synthetic natural gas, propane, distillate oil, syngas, and ultra-low 

sulfur diesel.

Commenter 20437 states that “[c]lean fuels” are used for ignition during startup and flame stabilization 

during shutdown. For most EGUs, primary fuel(s) also must be fired for some period of time during 

startup because the heat input produced from the ignition burners is not sufficient to achieve the 

temperatures necessary to bring some control devices on-line and that during shutdown, most units 

employ non-primary fuel, which can be “clean fuel,” to keep the flame stable as primary fuel is phased 

out during the shutdown process; however, during that process, some primary fuel may continue to be 
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combusted even after the EGU no longer generates electrical energy or makes useful thermal energy. 

Commenter expresses concern that other proposed language does not clearly manifest recognition that 

EGUs will fire primary fuel(s) while in startup or shutdown, and will use “clean fuels” only for ignition 

during startup and for flame stabilization during shutdown. As such, commenter recommends revisions

as follows to Table 3 of subpart UUUUU (as proposed in November 2012, see 77 FR 71342, second and

third lines of item 3) and to 40 CFR 63.10011(f) (as proposed in November 2012, see 77 FR 71338) to 

reflect that intent:

Prior to firing coal. residual oil, or solid oil-derived fuel during startup of an EGU, you 

must use one or a combination of the following clean fuels: natural gas, synthetic natural 

gas, propane, distillate oil, syngas, and ultra-low sulfur diesel, and other clean fuels as 

approved by the permitting authority for ignition.

(f) You must use for ignition during startup and flame stabilization during shutdown any 

one or combination of the following clean fuels: natural gas, synthetic natural gas, 

propane, distillate oil, synthesis gas (syngas), and ultra-low sulfur diesel (ULSD), and 

other clean fuels as approved by the permitting authority.

Response to Comments 100 and 101: The final rule retains the requirement that EGUs begin startup on 

startup (“clean”) fuel and maximize the use of clean fuels until startup has ended. PM controls must be 

operational within 1 hour of coal combustion. EGUs that are currently unable to come up to the requisite 

temperature due to a lack of clean fuel capacity will be required to increase their clean fuel capacity to 

the extent necessary to comply with the work practice standard. After the EGU begins firing coal, 

residual oil, or solid oil-derived fuel, the final rule requires the EGU to continue to maximize the use of

the clean fuels defined in 40 CFR 63.10042 and the EGU must engage its PM control device within 1 

hour of when the EGU starts firing coal, residual oil, or solid oil-derived fuel. Thereafter, the EGUs 

must comply with the MATS numerical emission limits within 4 hours of start of electricity generation.

As noted elsewhere, the EPA believes that its analysis of the startup practices of the top performing 

EGUs and its final definition of “startup” adequately balances commenters’ concerns with the 

requirements of CAA section 112. The EPA notes that the goal of the analysis was to identify the 

approximate time it took, on average, to initiate operation of APCDs by the top performing 12 percent of 

EGUs to determine a reasonable time after electricity generation to define the end of startup. The goal 

was not to seek the time it took for APCDs at all EGUs to become fully operational, and sources are not 

in fact required to engage their non-PM controls within 4 hours unless those controls are necessary to 

comply with any applicable requirements, including the MATS requirements. The EPA has determined 

that it will be possible for sources to accurately measure HAP emissions using CEMS at this time, and, 

for that reason, the work practice must end and the numerical emission limits must apply consistent with 

CAA sections 112(d) and 112(h).

As noted in the final preamble (77 FR 9401), “Liquid oil-fired EGUs subject to this [limited use liquid 

oil-fired] subcategory would be required to conduct the same initial and periodic tune-up as all other 

affected units, but would have no other emission limit or work practice requirements.” Thus, the startup 

provisions do not apply to EGUs in this subcategory.

We have addressed specific concerns related to PM control equipment in section 3.0 of this document.
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The EPA also received comments related to the safety issues that must be considered during startup of 

PM controls (e.g., CO buildup, fabric blinding). We note that these concerns are generally associated 

with temperature issues that we believe can be remedied through an increase in clean fuel capacity or 

other modifications to the clean fuel burners or other boiler system modifications. Comments suggest 

that the concerns about safety can be redressed with changes to the system that the commenters allege 

are not worth it. We note that NESHAP standards are designed to force the poorer performing sources to 

adjust their facilities to meet the HAP emissions levels of the best performing sources, and that mandate 

almost always comes at a cost to some sources in the category. However, we recognize that there may be 

very limited circumstances that compel some alternative approach for a specific EGU. Sources that can 

demonstrate that their EGU has a documented manufacturer-identified safety issue that cannot be 

resolved should seek an alternative compliance method consistent with 40 CFR 63.6(g). In its request 

for the case-by-case determination, the EGU must provide documentation that demonstrates that it is not 

technically feasible to bring the PM control device on line safely using clean fuels alone, and explains 

what other measure the source will take to ensure comparable HAP emissions to those required under 

the final work practice.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

2.1 Oppose

Comment 102: Commenter 20422 opposed eliminating the current requirement that only clean fuels be 

burned during startup. Commenter states the EPA should set performance standards for clean fuels to 

assure that alternatives are as clean as NG or distillate. Commenter states the EPA should define a set of 

performance standards for clean fuels, based on the properties that produce the lowest levels of toxic 

pollutants regulated under the rule during startup or shutdown. Commenter notes this approach is 

protective and would flexible enough to avoid endless review of petitions to add new substances to the 

list. Commenter suggests the EPA should limit the S content, Cl content, density viscosity, boil(ing)

point range, and distillation temperatures (D10, D50, and D90, representing temperature at which 10 

percent, 50 percent, and 90 percent of fuel will burn off).

Commenter 20436 states that the final MATS rule required EGUs to use natural gas, distillate, or low 

sulfur diesel fuels to ignite boilers and warm up pollution control equipment prior to electricity 

generation. Commenter opposes any weakening of these limitations (e.g., by requiring that EGUs only 

“maximize” use of clean fuels prior to generation). Commenter further alleges that the term “maximize” 

is vague and unenforceable and would create an unlawful new loophole and would not discharge EPA’s 

obligation to be consistent with CAA section 112(d). Commenter notes that, at a minimum, the EPA 

must require that the emission limits take effect as soon as coal combustion begins, whether or not 

electricity is generated.

Response to Comment 102: The EPA believes that its final definition of “clean fuels” includes fuels 

that all have inherently low levels of HAP. The EPA does not believe that adding performance standards 

as commenters suggest would be practical nor is it necessary.

As in the final rule, the EPA is requiring EGUs to maximize the use of clean fuels at the beginning of 

startup and to continue to maximize the use of clean fuels for as long as necessary to bring the EGU to 
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the temperature required to engage and operate the PM controls within one hour of coal, residual oil, or 

solid-oil derived fuel being charged to the units. This requirement is intended to ensure that PM and the 

attendant HAP reductions will occur as quickly as possible after primary fuel combustion begins. In 

addition, throughout the remainder of the startup period, EGUs are required to continue to maximize the 

use of the clean fuels. We consider this language to mean that EGUs will continue to use the maximum 

amount of clean fuels possible throughout the startup period to minimize HAP emissions.

2.2 Co-firing with other fuels

Comment 103: Commenter 20403 states that the EPA needs to acknowledge in the rule that as part of 

start-up a coal refuse-fired CFB will initiate startup using clean fuel and slowly transition from just 

firing with clean fuel to co-firing with clean fuel and coal refuse (along with limestone and/or ash) with 

the amount of clean fuel being reduced until the bed is stabilized using ever increasing amounts of fuel, 

limestone and ash. Commenter states that once the bed is stabilized the use of clean fuel is stopped.

Response: The CFB will be required to maintain the maximum clean fuel input possible throughout the 

startup period as it gradually increases its coal refuse and other inputs. See response to previous 

comments in section 2.0 above.

Comment 104: Commenter 20393 disagreed with the statement that no technical barriers exist to 

burning clean fuels for longer portions of startup or shutdown periods. Commenter states that with 

regard to particularly older and smaller EGUs, barriers do exist and that it would take too long to reach 

the proper combustion temperatures solely on clean fuels. Commenter states that this is due to the design 

of the igniters which were not designed to provide temperature regulation.

Commenter 20391 supports expanding the definition of “clean fuels” in the context of startup, shutdown 

periods. Commenter states that however, the EPA should limit the requirement to use clean fuels during 

startup exclusively to ignition. Commenter generally supports the proposed expansion of the clean fuels 

list. Commenter states that the EPA should provide greater flexibility and clarity in the “clean fuels”

definition by adding the language “and other clean fuels as approved by the permitting authority.”

Commenter 20391 states that the proposed reconsideration rule appears to require the use of clean fuels 

throughout the startup process, whereas the original final rule required use of clean fuels only for 

ignition. Commenter states that the EPA provides very limited explanation for the proposed change. 

Commenter states that other than asserting that no technical barriers exist to burning clean fuels for 

longer portions of startup or shutdown and that, if needed, an EGU could burn clean fuels until the 

appropriate flue gas conditions are achieved to engage APCDs. (EPA-HQ-OAR-2009-0234-20224.)

Commenter states that this requirement, however, would be problematic for EGUs that do not have the 

physical capability or adequate fuel supply to complete “startup” as defined by the EPA solely on a 

clean fuel. Commenter states that that to satisfy the work practice standards, some EGUs would need to 

modify their oil burner configurations, install additional piping and pumps, and/or increase storage 

capacity for clean fuels. Commenter states that in addition, firing clean fuels throughout startup will not 

allow the necessary temperatures for pollution control equipment to operate sufficiently and to its full 

potential. Commenter states that producing the initial flame in a PC boiler with oil works well, except 

the operating temperature of the SCR is not reached until 80 percent of coal mills are in service. 

Commenter states that having clean fuel capacity to reach this operating point would require significant 
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changes to the boiler and would create problems for the add-on air pollution control, such as ESP’s (e.g., 

fouling of surfaces that would prevent proper PM collection and can take days to restore proper 

operation), and changing the chemistry in the FGD that would delay proper operation. Commenter states

that in a CFB EGU, if gas was required to be used for startup, there could be significant increases in 

NOx, SO2 and CO emissions because gas does not have sufficient radiant heat energy to heat the bed of 

ash up to temperature in a reasonable time to allow the calcification process to function to begin 

injecting coal and limestone.

Commenter 20391 states that to the extent the EPA extends the clean fuels requirement beyond ignition, 

it should provide affected sources the opportunity to pursue alternatives with their permitting agency if 

burner configuration modifications or increased storage capacity that may be necessary to accommodate 

clean fuels are physically or economically prohibitive. Commenter states that clean fuels can also be 

scientifically not appropriate (e.g., gas fuel does not have the same radiant heat transfer properties as oil) 

and the use of gas may increase air emissions because of delays in heating up surfaces to allow 

transferring to the primary fuel.

Response to Comment 104: The EPA does not agree that the February 2012 final MATS rule only 

required the use of clean fuels for ignition. The work practice in the final rule required the use of only 

clean fuels until EGUs starting generating electricity, at which point the sources would be required to 

comply with the numerical emission limits. The record indicated that EGUs generally begin combusting

the primary fuel at approximately the same time as they begin generating electricity. As for controls, we 

stated in the final rule that PM and other controls had to be engaged at that time as necessary for the 

sources to comply with the numerical standards. As many industry commenters note, many PM controls 

cannot be engaged for some time if it is a cold or warm startup. Logically this would mean that EGUs 

would be required to combust only clean fuels for extended periods of time for cold and warm startups. 

Furthermore, the final MATS rule defined the end of startup as the first generation of electricity or 

thermal energy for sale or on site use. Again, many industry commenters indicated that they begin 

generating electricity simultaneously or soon after adding the primary fuel to the EGU. Because sources 

would be required to comply with the numerical standards at the time of electricity generation, which is 

earlier than under the alternative set forth in this final rule, we believe that clean fuel capacity increases 

and other modifications (e.g., to burners) would have been necessary for many EGUs to allow them to 

burn clean fuel alone for a longer period under the final rule definition for sources to be sure they would 

comply with the numerical standards once generation occurred.

The EPA believes that its analysis of the startup practices of the top performing 12 percent of EGUs, 

which included all types of EGUs, its final definition of “startup,” and its final definition of “clean 

fuels” adequately balance commenters’ concerns with the requirements of CAA section 112. The EPA 

continues to believe that commenters’ “technical barriers” associated with using more clean fuel during 

startup can be resolved at almost all, if not all, EGUs. Sources will need to determine the appropriate 

approach to comply with the final rule consistent with the individual EGU’s needs in the same manner 

owners and operators evaluate their sources when determining how to comply with numerical limits. 

The EPA’s final rule is not flawed if it requires sources to make investments that will reduce HAP 

emissions, as the commenters imply.

Comment 105: Commenter 20415 states that the commenters submitted data and information showing 

that it is common and necessary for boilers to begin to fire primary fuel in addition to the startup fuel 
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before certain APCDs are engaged. Commenter states that this is most often due to the inability of the 

boiler igniters to bring the boiler up to temperatures high enough to operate APCDs because igniters and 

their associated fuel supply systems are typically of very limited heat input capability. Commenter states

that in addition to these operational limitations, worker safety concerns also require that certain 

operating conditions be met prior to engaging APCDs. Commenter states that a typical coal-fired EGU

may use clean fuel initially to ignite some coal and then slowly build enough heat for the boiler to be 

fully operational. Commenter believes the rule should clearly recognize that a transition to base or 

primary fuels that are not defined as clean (e.g., coal or biomass) is an integral and essential step in the 

startup process and must be allowed regardless of whether any steam or heat output is generated.

Commenter 20415 states that the EPA has provided additional clarity of this issue in the Boiler MACT

Final Reconsideration Rule, which commenter recommends the EPA adapt to the MATS rule as well, 

because some EGUs may utilize these types of startup fuels. Commenter states that in the Boiler MACT

rule, the EPA expressly recognizes the following as clean fuels for use during startup: natural gas,

synthetic natural gas, propane, distillate oil, syngas, ULSD, fuel oil-soaked rags, kerosene, hydrogen, 

paper, cardboard, refinery gas, and liquefied petroleum gas. Commenter states that this list is more 

inclusive than the MATS rule definition and reflects the reality that during startup, boilers are designed 

for certain startup fuels and only certain fuels may be available. Commenter states that it is important to 

note, however, a major deficiency of the MATS and Final IB MACT rule definitions of startup is that 

neither expressly recognizes that many EGUs must co-fire and then switch over entirely to primary fuels 

in addition to these clean fuels during the startup period. Commenter states that therefore, an expanded 

list of clean fuels must be coupled with a workable definition of startup, which includes switching over 

to the primary fuel during the startup period, to rationally reflect the realities of boiler operations.

Commenter 20393 disagreed with the EPA and states that EGUs cannot generate adequate heat to 

energize the ESP even if they combust only oil or gas startup fuel for an extended period of time and 

states that the current work practice requirement is not feasible for many coal-fueled EGUs equipped 

with ESPs. Commenter states that many coal-fueled EGUs must combust coal along with oil or gas 

during startup in order for the ESP to achieve adequate temperatures for the proper and safe operation of 

the control equipment. Commenter states that without the combustion of coal, many utility boilers will 

not be able to generate sufficient heat to achieve the manufacturer’s recommended minimum 

temperature levels for the ESP while burning only oil or gas startup fuels. Commenter states that older 

design coal-fired EGUs have oil or gas igniters that were never designed to preheat the ESP plates 

without the combustion of coal and will be unable to provide sufficient heat to warm up the ESP 

hardware to the manufacturer’s specified temperature levels. Commenter indicated that operational 

manuals for five different boiler/precipitators used in commenter’s facilities require minimum ESP inlet 

temperatures of between 200 and 275 °F prior to energizing the ESP.

Commenter 20421 asks that co-firing of coal be permitted during startup, and asks for language to 

clarify that co-firing coal during the startup period is permitted by the regulation. Commenter states that 

most coal-fired EGUs were not designed nor do they have enough capacity in their ignition/startup 

burners to achieve permissive temperatures to operate their APCDs without the use of coal in addition to 

the use of clean fuels during startup. Commenter maintains that in order for some coal-fired EGUs to use 

only clean fuels during startup, significant capital investment in redesign and retrofitting facilities would 

be required, at a prohibitively high cost that the EPA has not measured or evaluated in developing the 

rule (presupposing that there is a sufficient supply of clean fuel available to the EGU, which is not likely 
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in many cases). Commenter notes that the plain language of Reconsideration Rule contemplates the cofiring of startup and primary fuels during startup. Commenter recommends the following text be 

included in Table 3:

Coal-fired EGUs are permitted to co-fire coal with their clean fuels when needed to 

complete the startup phase of operation.

Commenter 20430 states that that its San Miguel EGU is unable to meet the criteria of completing 

startup as originally proposed using only “clean fuel.” Commenter states that San Miguel requires cofiring of clean fuel with the primary fuel in order to reach a proper temperature to produce electric 

generation. Commenter states that San Miguel’s steam generator design does not include large oil guns 

but is designed with oil igniters (firing #2 fuel oil) that do not permit the EGU to be synchronized 

(generate electricity) or safely initiate APCDs prior to firing primary fuel. Commenter requests the 

ability to co-fire startup fuel and primary fuel through initial synchronization.

Commenter 20408 states that the wording of the proposed rule seems to preclude the use of the primary 

fuel (e.g., coal, residual oil) during startup. Commenter alleges that the EPA apparently does not 

recognize that the generation of electricity begins typically while both the startup fuel and primary fuel 

are still being fired together. Commenter provides an informative example of a staged startup with a 

cyclone boiler EGU. Typically cyclone boilers have 10-20 individual cyclones. A typical startup 

procedure for a cyclone boiler is to warm 1-3 cyclones using startup fuel and as these cyclones come up 

to temperature the operator begins feeding the primary fuel (e.g., coal). After these initial cyclones are 

on line and using coal the EGU will typically begin generating electricity rather than waste this energy 

in the steam cycle. The remaining cyclones are brought on line in the same manner incrementally. The 

boiler is thus not fully finished with startup until all available cyclones are online. Commenter states that 

the EPA needs to revise the statement in 40 CFR 63.10011(f) clarifying and recognizing that the primary 

fuel can be burned during startup.

Response to Comment 105: The EPA has acknowledged elsewhere in this document that it is aware 

that both clean fuels and the primary fuel may need to be used together during startup and that such 

acknowledgement was in both the final rule and proposed reconsideration. The EPA has also noted that 

it believes almost all, if not all, the identified technical barriers to increasing the amount of clean fuel 

can be addressed through an increase in clean fuel capacity and/or other modifications to the facility or 

operational practices. As stated above, the EPA does not believe a work practice standard should be set 

at the level all sources can meet unless all sources are virtually identical, as that is not consistent with 

CAA section 112(h).

Comment 106: Commenter 20391 states that the EPA should not apply the clean fuel requirement for 

oil-fired EGUs that fall under the limited use liquid oil-fired subcategory of the MATS rule. Commenter 

states that the limited use EGUs will not be subject to emissions limits if a particular EGU is under the 8 

percent annual capacity factor limit. Commenter states that these EGUs should not be required to absorb 

the additional capital expense to modify their SS process and additional operating expenses for startup 

given their limited use and the limited environmental benefit that would be realized. Commenter states

that MATS should be revised to reflect that these limited-use EGUs are only required to perform the 

boiler tune-up work practice standards and keep records to demonstrate compliance with the 8 percent 

annual capacity factor limit.
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Response to Comment 106: As noted in the final preamble (77 FR 9401), “Liquid oil-fired EGUs 

subject to this [limited use liquid oil-fired] subcategory would be required to conduct the same initial 

and periodic tune-up as all other affected units, but would have no other emission limit or work practice 

requirements.” Thus, we do not interpret the rule to apply the startup (or shutdown) provisions to EGUs 

in this subcategory. We meant this quoted language to indicate that to be our intent but in light of the 

comment, we have added exclusionary language to Table 3 of subpart UUUUU for clarification.

Comment 107: Commenter 20407 states that that the definition of fuel that can be used during startup 

period should be removed from the rule. Commenter supports the EPA’s recognition in the 

reconsideration that the EGU’s primary fuel, in most cases, must be utilized during the startup period to 

complete the startup process. Commenter states that based on its experience, the temperatures needed to 

safely start various emission control equipment cannot be achieved without introducing the primary fuel 

to the EGU. Commenter states that the startup and shutdown plan should set forth the procedures, 

including fuels used, to startup an EGU as expeditiously as possible. Commenter states that at a 

minimum, the EPA should revise the work practice standard to clearly indicate that the primary fuel for 

the EGU can be used during the startup period.

Commenter 20390 states it may not be possible at every plant to bring the system up to temperature with 

clean burning startup fuel and bring APCD into service prior to firing coal. Commenter states that at 

some plants startup fuel is co-fired until half load and at other facilities startup fuel is co-fired until twothirds load, and indicates the capacity for auxiliary or startup fuel of each plant is different, noting that 

some plants burn startup fuel to 10 percent of design heat input whereas others can burn auxiliary fuel 

up to full load. 

Commenters 20417 and 20419 also urge the EPA to consider that defining the end of startup based on 

when coal, residual oil, or solid oil-derived fossil fuels are first fired is impracticable at certain plants. 

For example, Commenter 20419 indicates that one member owns a coal-fired EGU that uses natural gas 

to ignite the coal, but lacks sufficient natural gas capacity to the plant to allow the EGU to complete the 

startup process. Due to this supply limitation, Commenter 20419 alleges that coal must be fired within 

the first 30 minutes of the startup process but the plant cannot begin to generate electricity for 

approximately 7 hours. Commenter 20419 notes that the EGU’s ESPs are started when the switch to 

coal is made and the ESPs are shut off and the baghouse is put in service when the flue gas is up to 

proper baghouse operating temperatures that are above the moisture dew point (based on further 

analysis, commenter now believes that that baghouse operations are constrained by the moisture dew 

point, not the acid dew point). Commenter 20419 maintains that, as written, Table 3 suggests that startup 

at this EGU ends once the plant begins to burn coal, which is too early – if the EGU puts the baghouse 

into service before the flue gas is above the moisture dew point, the EGU would experience bag 

blinding. Commenter 20419 notes that another member’s EGU begins startup by firing distillate oil; 

however, it must fire coal early in the startup process to reach the temperatures necessary to complete 

the startup process and it is technically infeasible for the EGU to initiate operation of the ESP when it 

first fires coal, because the EGU still contains oil. Commenter 20419 maintains that operating the ESP 

while the EGU contains oil can cause fouling of the ESP, in which a film coats the ESP and can result in 

substantial equipment damage and a reduction in emissions control efficiency (operating the ESP while 

it still contains oil also can cause serious safety risks; oil residues may combust when the ESP sparks, 

which could start a fire). Commenters 20417 and 20419 say, for many EGUs the startup of their 
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emission controls is dependent on achieving the proper temperatures to safely and appropriately place 

the emission controls into operation. Commenters state, it is often the case that primary fuel firing (i.e., 

coal, residual oil or solid oil-derived fossil fuels) is needed for EGUs to obtain those proper 

temperatures. Commenters say start-up fuels (i.e., natural gas or distillate oil) alone may not provide the 

proper heat input to produce the temperatures needed for proper operation of the emission controls. 

Commenters, therefore, request that the EPA not define the end of startup based on when coal, residual 

oil, or solid oil-derived fuels are first combusted as currently stated in Table 3.

Response to Comment 107: See responses above concerning the technical concerns identified in these 

comments. The EPA believes that its analysis of the startup practices of the top performing 12 percent of 

EGUs, which included all types of EGUs, and its final definition of “startup” adequately balances 

commenters’ concerns with the requirements of CAA section 112. The EPA has acknowledged 

elsewhere in this document that it is aware that both clean fuels and the primary fuel may need to be 

used together to bring certain non-PM controls on line and that acknowledgement was in both the final 

rule and proposed reconsideration. The EPA believes it is appropriate to define what fuels are “clean” 

and, therefore, suitable for use during periods of startup and shutdown so as to minimize HAP 

emissions.

Comment 108: Commenter 20421 disagreed with the requirement for clean fuel (i.e., natural gas or 

distillate oil) for SS of stoker coal-fired boilers. Commenter states that its boilers’ initial design features 

did not include the ability to start up on natural gas or distillate fuel and the facilities have no gas or 

distillate oil available on site. Commenter indicates that switching to natural gas for startup is not 

feasible due to the inaccessibility of the natural gas supply and an indefensibly high cost to gain access 

to natural gas and retrofit facilities to startup on natural gas. Commenter states that retrofitting each of 

its facilities to utilize natural gas or distillate oil solely for use during SS periods, is not feasible, is not 

supported by the rulemaking record, and is not justified by corresponding environmental benefit.

Commenter alleges that the costs for infrastructure to supply natural gas to each of its facilities render 

natural gas a non-viable compliance option. Commenter provides estimates from natural gas providers 

for each facility that include the annual costs (over 15 years) of pipeline construction (which include gas 

system upgrades, new 10,000 foot lateral pipeline, metering and reducing station, etc. and will take 3 

years upon authorization) along with boiler modifications. Commenter states that these estimates ranged 

from $3.8 to $7 million per EGU. Commenter notes that these estimates do not include the cost of the 

natural gas and that one-time costs for EGU modifications are also estimated. Commenter also provides

similar cost estimates for distillate oil that range from $3.1 to $3.2 million per EGU.

Comment 109: Commenter 20421 states that the required infrastructure (truck unloading and 

containment stations and distillate storage tanks) necessary to use distillate oil as the startup fuel would 

be particularly problematic at its Spruance facility due to existing site congestion – Spruance is 

comprised of 8 boilers, switchyard, coal storage, 2 5-cell cooling towers, warehouse, craft shops, 8

scrubbers, 8 baghouses, 4 turbine-generator sets, and all ancillary equipment typically required to 

support an EGU, all of which is located on just 22 acres.

Response to Comments 108 and 109: The EPA believes that the final definition of “clean fuels” 

adequately accounts for commenters EGUs. Generally, a valid CAA section 112(h) standard will require 

many sources in a category to make investments that will reduce HAP emissions. Commenter does not 

indicate its current method of startup of its stoker boilers but the EPA believes that if a substrate soaked 
118

with (e.g.) diesel fuel or distillate oil is used in startup, it is this diesel fuel or distillate oil that is the 

“startup” fuel rather than the substrate; as long as these diesel fuels or distillate oil meet the definition of 

“clean fuel” in the final rule, they would be appropriate for use during startup.

Comment 110: Commenter 20413 states that the EPA is proposing the use of cleaner fuels such as fuel 

oil only or natural gas only during the entire period defined as startup. Commenter operates a coal-fired

cyclone boiler that is designed to combust fuel oil as a startup fuel before slowly transitioning to 100 

percent coal combustion. Commenter states that the configuration and design of this boiler does not 

allow for the use of only fuel oil from the time of the initial start of the EGU to the point of electricity 

generation and full activation of all pollution control equipment. Commenter asks that the EPA take into 

consideration how startup fuel feed systems must rely on a mixture of both cleaner fuels and coal in 

order to complete the defined startup period for coal-fired cyclone boilers.

Response to Comment 110: The EPA believes that its responses above concerning technical concerns 

with compliance address this comment.

2.3 Edit to standard

Comment 111: Commenters 20417 and 20419 ’say, as written, Table 3 suggests that startup ends, and 

normal operation begins, once an EGU converts to firing coal, residual oil, or solid oil-derived fuel. 

Commenters note, however, this is inconsistent with the proposed definitions for the end of startup in the 

Proposed Reopening which defines the end of startup based on hours after 25 percent load is first 

reached or hours after first electricity generation, as well as with the proposed definition of startup in the 

Proposed Reconsideration Rule (which defines startup in reference to the generation of electricity that is 

sold or used for any other purpose). Commenters request that the EPA revise Table 3 to be consistent 

with the final definition of startup to eliminate regulatory ambiguity.

Response to Comment 111: The EPA believes that the finalized definition and table eliminate any 

regulatory ambiguity.

3.0 APCD OPERATION

Summary of Comments Received Following November 30, 2012, Proposal

3.1 Startup

Comment 112: Commenters 20248, 20251, 20254, 20267, 20269, 20272, 20273, 20275, 20276, 20279, 

20286, 20287, 20288, 20289, 20295, 20297, 20303, and 5803 express concern over the proposed 

requirements to start up only the listed control devices when the primary fuels are introduced and state

that control devices such as baghouses and ESP, which are not listed, should be included in the list of 

controls that need not be operated until it is technically feasible. Commenters recommend that the rule 

be revised to allow all control equipment to be started as expeditiously as practicable after initiating 

startup operations. Commenters states that to do otherwise would be contrary to manufacturers’

specifications and good engineering practices, would risk damage to the control equipment and could 

result in unsafe conditions.
119

Commenter 20254 states that the requirements that baghouses must be in use as soon as any coal is 

burned in the boiler is not consistent with equipment manufacturers’ specified operating procedures, 

especially for older or smaller coal fueled boilers that are not able to achieve the correct temperature for 

the operation of a baghouse while using the igniter to burn a “clean fuel” as required under the MATS 

startup work practices standards. Commenter states that in many instances the igniter offers only a low 

heating value, especially on older and smaller EGUs and therefore cannot serve a heating function well 

over long periods of time and would thus require a large number of additional hours to reach proper 

startup temperatures if an EGU is solely using the igniter and a clean fuel. 

Commenter 20254 states that it may be impractical to get the boiler up to the correct temperature where 

natural gas is the only fuel used as it could require a large amount of natural gas and there may be 

natural gas supply concerns for these EGUs, for example, where the natural gas pipeline capacity is 

limited. Commenters 20254 and 20288 state that at EGUs that must burn coal to reach the correct 

temperature, starting up the baghouse immediately upon combusting coal would be inconsistent with the 

manufacturers’ specification for the proper and safe operation of the baghouse. 

Commenter 20254 states that if the EPA does not allow for baghouse startup flexibility, commenter

urges the EPA to provide clarification that installation of new and additional burners to preheat the 

baghouse would not be considered a modification for purposes of NSPS and NSR programs.

Commenter 20321 states that its plant follows procedures based on the manufacturer’s recommendations 

and the plant’s experience, which require it to maintain flue gas temperatures for over 2 hours before its

ESP can be energized. Commenter states that premature starting of controls damages air pollution 

control device equipment.

Commenter 20272 states that if the EPA does not determine that an exception during startup regarding 

ESPs is warranted, it must at least ensure that the installation of additional burners to pre-heat the ESP 

be classified as a pollution control mechanism and not considered a modification for purposes of NSPS 

and NSR programs.

Commenter 20269 asks that the EPA allow EGUs to start ALL pollution control devices when it is 

technically feasible. Commenter notes that the type of control device, the local weather conditions, flue 

gas temperature, and safety concerns influence when startup is technically feasible.

Commenter 20303 suggests the time frame between coal combustion and all air pollution devices in 

operation be “as soon as practicable” allowing a grace period of one hour.

Commenter 5803 requests that the EPA continue to review and reconsider the operating constraints of 

all other emission control systems as they relate to the startup of EGUs in this rule.

Commenter 20275 states that due to existing EGU design, it may be necessary for the boilers of certain 

low-rank coal EGUs to reach established air temperatures before pulverization of the coal begins and 

then require additional time for the phased-in operation of environmental controls - specifically ESPs. It 

is commenter’s experience that it should take no more than one hour to phase in ESPs once 

pulverization commences. Commenter states, therefore, the pollution control requirements for coal-fired 

EGUs during startup should be required “as soon as practicable,” rather than immediately upon startup, 
120

or at a minimum, the EPA should provide a grace period of at least one hour after boilers reach 

temperatures necessary for pulverization to begin operation of all control technologies.

Commenters 20272 and 20288 express concern that many coal-fueled EGUs must combust coal along 

with oil or gas during startup in order for the ESP to achieve adequate temperatures for the proper and 

safe operation of the control equipment. Commenters ask that the EPA should note that the use of oil 

and coal during startup is not binary, but rather operates on a continuum. Commenters recommend that 

the EPA define work practices for control systems, including EPSs, material injection systems and 

baghouses, based on vendor recommendations and engineering practices for each system type, which are 

outlined by commenters. 

Commenter 20286 states that the requirement regarding operation of pollution control equipment during 

startup operations should be revised to be more general or provide for case-by-case exemptions beyond 

the specific list of equipment the EPA has exempted. Commenter states that the EPA should revise the 

provision to require the source to start all pollution control equipment as expeditiously as practicable 

after initiating startup operations. Commenter states that alternatively, the EPA could include a petition 

process allowing for case-by-case exemptions to provide additional flexibility. Commenter states that if 

only certain pollution control equipment are exempted, then the EPA must periodically reevaluate the 

exempted equipment as pollution control technology advances and revise the rule accordingly or the 

provision could become a disincentive to the deployment of newer technology.

Commenter 20297 states that its warm-up burners, firing ULSD, are rated to supply only about 5 percent 

of the rated continuous heat input required for EGU operation and cannot bring the EGU and associated 

air pre-heaters, two stages of ESP, and FGD up to anywhere near the temperatures required for safe 

operation. Commenter notes that it can take up to several hours of coal combustion at minimal operating 

loads to achieve temperatures necessary for safe operation of the ESPs, ACI, and FGD. Commenter

states that this requirement is part of its Title V permit which allows up to 8 hours for a staged startup of 

the emission control from the time the EGU is on the grid. Commenter states that the proposed language 

does not recognize that there are multiple stages of applicable emission control equipment that must be 

started up in sequence and in the proper order. Commenter recommends revising section 3 of Table 3 

and provides example language.

Commenter 20273 recommends that in Table 3 a qualifier such as “within the constraints for normal 

startup of the EGU and dry scrubber,” after “as expeditiously as possible” be added to the language. 

Commenter states that this would address the need for the CDS to attain the temperature necessary to 

start the system.

Commenter 20248 requests ESP to be added to this list of control devices in Table 3 or alternatively, 

that language be added to the MATS rule allowing for special consideration for unit-specific issues for 

safely bringing control devices into operation as may be addressed by local permitting agencies and 

incorporated into an EGU’s operating permit.

Commenter 20287 states that to eliminate ambiguities, the final rule should reflect the temperature 

constraints of dry scrubber, SNCR and SCR systems explicitly in Table 3 and indicate that operation of 

these systems is not required unless appropriate temperatures have been reached.
121

Commenter 20272 states that affected coal-fired EGUs should not be required to place their ESPs into 

service until coal has been continuously combusted for 3 hours and the ESPs have reached safe 

minimum temperatures in order to prevent fires and/or explosions within the precipitators. Commenter

cites two separate consent decrees that allow for this.

Commenter 20251 states that ESPs, baghouses, and DSI systems should also be treated as SNCR, SCR, 

and dry scrubber systems, and should not be engaged once firing of coal is started. Commenter suggests

the following startup language for Table 3 of the proposed rule for coal-fired, liquid oil-fired, or solid 

oil-derived fuel-fired EGU:

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions 

to the main stack(s) and engage all of the applicable control devices except limestone 

injection in FBC EGUs, dry scrubber, SNCR, and SCR. You must start your limestone 

injection in FBC EGUs, dry scrubber, SNCR, and SCR control equipment systems as 

expeditiously as possible, but, in any case, when necessary to comply with other 

standards applicable to the source that require operation of the control devices.

An alternative would be: 

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions 

to the main stack(s) and engage all of the applicable control devices except limestone 

injection in FBC EGUs, dry scrubber, ESP, baghouse, DSI, SNCR, and SCR. You must 

start your limestone injection in FBC EGUs, dry scrubber, ESP, baghouse, DSI, SNCR, 

and SCR systems control equipment systems as expeditiously as possible, but, in any 

case, when necessary to comply with other standards applicable to the source that require 

operation of the control devices. 

Commenter 20288 states that companies should be allowed to specify that startup period ends for 

purposes of the Hg MATS limit when affected EGUs equipped with SCRs and FGDs are both placed 

into service given that optimal Hg controls will not occur for many EGUs until this combination of 

emissions control equipment is in full service.

Commenter 20279 urged the EPA to consider that new pollution control devices will be developed in the 

future which may have similar technological limitations on operation during startup and shutdown. 

Commenter also states that the EPA should provide that all pollution control technology that cannot 

operate during startup and shutdown conditions begin operating when it is practicable to do so, rather 

than specifically providing an exception for limestone injection, dry scrubbers, SNCRs, and SCRs 

(commenter notes that certain EGUs cannot start ESPs prior to combusting coal and that an ESP also 

requires a two-to-one coal-to-oil burn ratio to minimize the risk of explosion due to sparking in an 

energized field).

Response to Comment 112: As stated in response to other comments on the technical issues 

associated with compliance with the final work practice, the EPA believes that there are 

solutions to all or almost all of those issues. In addition, the EPA believes that its analysis of

multiple years of data for the startup practices of the top performing 12 percent of EGUs, which 

included all types of EGUs, and its final definition of “startup” adequately balances commenters’ 
122

concerns with the requirements of CAA section 112. In addition, as noted in the response to 

comments 89 and 90 above, we have included a provision whereby EGUs may petition for an 

alternate time by which PM APCDs must be engaged.

Comment 113: Commenter 5803 agreed with the EPA’s expanded list of exempted controls.

Response to Comment 113: This comment requires no response.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

3.2 General

Comment 114: Commenter 20427 states that contemporary Hg, PM, and acid gas APCDs can be 

operated at all times that coal is burned at an EGU. Commenter states modern PM, acid gas, and Hg 

APCDs achieve peak pollution reductions within minutes of engagement of the APCD. Commenter 

states that even were some temperature threshold to exist, which it does not, neither industry nor the 

EPA has provided any basis for creating a 4- to 6-hour exemption between reaching that threshold and 

application of the numeric standards, nor is there any basis to exempt plants from numeric standards 

when coal is burned prior to electricity generation.

Commenter 20433 rebutted Commenter 20427’s assertion that controls are immediately effective, 

including in its comments on the proposed reconsideration rule (EPA-HQ-OAR-2011-0044-5794). 

Commenter 20433 notes, e.g., the Hg emissions of an EGU may spike significantly after electricity 

generation begins but before the emission control devices are fully operational. In addition, some SCRs 

(which will be used for Hg oxidation and control) are designed to operate such that the SCR is bypassed 

until the startup fuel is removed to prevent catalyst contamination; once the startup fuel is removed, the 

SCR inlet dampers are gradually opened at a controlled rate of temperature change over a period of 

approximately 12 hours, depending on various conditions associated with each startup, to minimize 

thermal stress, ammonium bisulfate formation, and acid corrosion, and to prevent immediate structural 

damage within the SCR. Commenter 20433 states that the SCR can be fed ammonia only when the 

critical minimum operating temperature (typically 650 to 700 °F) is reached; during this period of SCR 

startup, Hg oxidation and Hg emissions are unpredictable.

Commenter 20427 states that the EPA should, at a minimum, retain the requirement that APCD be 

operated at all times that coal is burned, and the numeric standards be met whenever electricity is 

generated. Commenter states that available technologies allow combustion of NG or distillate oil to 

achieve normal operating temperatures and that operating temperature does not constrain plant-owners’

ability to operate pollution controls when coal is being burned in the boiler. Commenter states that the 

EPA’s argument that some igniters have a low heating value, and some igniters may not have sufficient 

capacity, and some igniters may not be able to generate adequate heat to preheat APCD even when 

operated for extended periods, are only applicable to a handful of older coal-fired EGUs. In addition, 

commenter states that the EPA’s argument that some pipelines are too small to provide sufficient NG 

capacity only affects a limited number of older coal-fired boilers. Commenter states that a few igniters 

of older design or smaller pipelines that need to upgraded or replaced does not demonstrate that the 

work practice is impractical or infeasible. Commenter states that igniters capable of reaching normal 

operating temperatures are readily available and in use at most contemporary coal-fired EGUs. 
123

Commenter states the Act’s air toxics provisions seek to ensure that older equipment is upgraded and 

improved, to reduce toxic pollution. Commenter states that with relatively modest investments, NG or 

distillate oil can be used to reach necessary temperature thresholds for APCDs at all pulverized coal 

plants.

Commenter 20433 rebutted Commenter 20427’s comment that “relatively modest investments” would 

be needed to reach the appropriate temperature thresholds. Commenter 20433 cites to previously filed 

comments (EPA-HQ-OAR-2009-0234-20400, -20281) and notes that the investments required to reach 

the temperature achieved through coal firing using only startup fuel are far from “modest.”

The systems that supply [startup] fuels to the boiler...are generally too small to replace 

coal. As an example, one type of coal pulverizer operated by Duke Energy has seven or 

eight individual burner lines, and it is used for both subcritical and supercritical units. 

Each of the burner lines is paired with an oil gun that is used to light the coal fire and to 

stabilize the coal flame when the pulverizer is operated at lower capacity. The heat input 

from coal for this pulverizer is about 1,200 MMBtu per hour, while the oil guns are only 

capable of delivering 17.5 MMBtu per hour. Clearly the oil guns do not have the capacity 

to deliver the same amount of heat provided by the coal pulverizers. Even if the oil guns 

were radically increased in total capacity, the rest of the system including tanks, pumps, 

piping, controls, etc. would all have to be increased to match. As a result substituting 

cleaner fuels in place of coal can have only a limited effect or would require extensive 

modification just to accommodate more use of these fuels during startup periods.

Commenter 20433 maintains that the theoretical investments required to get an EGU up to the same 

temperature reached during stable coal firing using startup fuel would be significant, not modest.

Comment 115: Commenter 20420 supports the EPA’s proposal to allow all of the applicable APCDs

except limestone injection in (CFB) EGUs, dry scrubber, SNCR, and SCR to be engaged during startup 

and disengaged during shutdown as appropriate based on temperature restrictions and other operational 

requirements. Commenter notes that the proposed changes will allow it to operate its dry scrubbers, 

SNCRs, SCRs, and limestone injection systems safely in accordance with manufacturers’ specifications.

Comment 116: Commenter 20421 states that the proposed definition for the end of startup for coal-fired 

EGUs makes compliance with the work practice standard possible for most coal-fired EGUs and agreed 

that most APCDs should be able to meet their permissive temperatures in the timeframe the EPA has 

used to define the end of startup, under normal conditions. Commenter notes, however, that the revised 

rule does not take into consideration unusual circumstances, nor does it consider EGUs whose APCD 

permissive temperatures extend beyond the period of time that the EPA has proposed that startup ends. 

Commenter states that such a requirement is untenable, because it imposes a regulatory requirement that 

some facilities are operationally incapable of meeting. Commenter suggests the following text to be 

added to the requirement that APCDs be engaged as expeditiously as possible: 

in accordance with original equipment manufacturer recommendations and prudent 

industry practices.
124

Commenter notes that even with the addition of this language, which would assist in compliance, the 

EPA must also address the more difficult issue of its limit on the timeframe for startup.

Comment 117: Commenters 20402 and 20404 state that the EPA’s definition of “startup” does not 

accurately reflect the end of the startup period, given that many of the APCDs need time to safely and 

effectively startup and operate. Commenter 20402 strongly supports the EPA revising the definition of 

startup to include the “end” point of 25 percent of nameplate capacity plus 3 hours or the start of 

electricity generation plus 6 hours, whichever comes first because it more accurately captures the period 

of time during which an EGU transitions from offline to fully operational and able to provide the 

defined electricity or steam demands. Commenter 20402 notes that, in addition, the revision recognizes 

the real operational differences among EGUs and indicates that clearly and accurately defining the end 

of startup is critical as it introduces the point in time when specific parameters are to be met, emission 

controls are to be fully operational, and the source is in compliance with applicable numeric emission 

standards. However, Commenter 20402 cautions the EPA that even this more flexible definition may 

exclude certain EGUs from complying with the rule, and recommends that an alternative petition 

approach be available to such EGUs.

Commenters 5833 and 5834 state that trying to operate or use installed emissions control equipment 

during SSM periods will damage the equipment, impact their ability to continue operation or meet 

permit conditions, and could violate manufacturer operational guidelines in many cases. Commenter 

5833 maintains that if the EPA promulgates the SSM proposal as described, electric reliability will be 

impacted and an overall increase in emissions could occur because of damage to APCDs.

Commenter 5833 notes that its emissions control equipment is designed to operate at minimum and full 

load for extended periods of time and will not operate at full efficiency during startup periods and that 

emissions during startup and shutdown periods are low due to the short period of time and its efforts to 

minimize startup and shutdown periods. Commenter indicates that some of its facilities and equipment 

must use alternative fuels during startup periods that emissions control equipment is not designed to 

target. Commenter alleges that, as the EPA knows, malfunctions cannot be anticipated or predicted and 

urges the EPA to try to avoid implementing a one-size-fits-all approach, especially given site-specific 

issues that may arise.

Commenter 20401 notes that because properly operated and maintained equipment will outperform 

improperly operated and maintained equipment, the EPA’s startup definition should be formulated in a 

way that maximizes utilities’ ability to meet the recommended requirements for proper operation as well 

as to avoid unnecessary safety risks and possible damage that would reduce the overall performance of 

the APCD, and that the startup definition should be revised to allow for the boilers and associated APCD

to go through all the recommended steps to reach flue gas conditions necessary for safe, stable 

operation. 

Response to Comment 117: The EPA believes that its analysis of the startup practices of the top 

performing 12 percent of EGUs, which included all types of EGUs, its final definition of “startup,” and 

its final definition of “clean fuels” adequately balance commenters’ concerns with the requirements of 

CAA section 112. Responses to the specific issues raised by commenters may be found elsewhere in this 

document. With regard to commenter’s statement “that some of its facilities and equipment must use 

alternative fuels during startup periods that emissions control equipment is not designed to target” – we 
125

are finalizing that all EGUs must use one (or more) of the clean fuels defined to the maximum extent 

possible during startup.

Comment 118: Commenter 20403 suggests a revision in the standard which would allow APCD to start 

as soon as technically feasible and not “at all times during startup” as previously written or process 

control to be implemented as soon as technically feasible. Commenter states that this addresses the 

concern of limestone injection in coal-fired CFBs but also includes other APCDs. Commenter states that 

all the APCDs should be allowed to meet their permissive temperatures in the time allotted under the 

proposed “end of startup” language.

Commenter 20410 states that if the EPA is going to take the current proposed approach, the excluded 

controls should also include ESPs, baghouses, and DSI.

Comment 119: Commenter 5834 recommends that proposed Table 3, work practice 3, paragraph 4 be 

revised to except other APCDs as follows (revisions indicated with underlines):

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent the 

emissions to the stack(s) and engage all of the applicable control devices except ESPs, 

ESPs in combination with activated carbon injection, limestone injection in FBC EGUs, 

dry scrubber, SNCR, and SCR. You must start your ESPs, ESPs in combination with 

activated carbon injection, limestone injection in FBC EGUs, dry scrubber, SNCR, and 

SCR systems as expeditiously as possible, but, in any case, when necessary to comply 

with other standards applicable to the source that require operation of the control devices.

Comment 120: Commenter 20426 recommends that the work practice standard consider the type of 

APCDs used and define the startup period (start to end) to accommodate the time necessary for this 

equipment to be placed into operation. Commenter states that, the period of startup and shutdown needs 

to take into consideration the limits of the APCD that is used to meet the applicable MATS limits. 

Commenter states that the work practice must be clear that the end of startup occurs when conditions 

meet a minimum level that is associated with the proper operation of the pollution control equipment 

and the method utilized. Commenter states that, without this consideration, the period of time between 

the end of startup of the EGU and the time when a specific pollution control system must start may 

cause the source to exceed the limit, even considering the 30-day averaging period. Commenter states

that the testing used for developing and setting the emission limits included stack testing when the EGUs 

are operating at full load, or the predominately normal operating load, under steady state conditions. 

Commenter states that startup by definition is a transient condition that exposes the equipment to 

changing conditions and this reality must be adequately considered in the final rule.

Response to Comments 118 - 120: The EPA believes that its analysis of the startup practices of the top 

performing 12 percent of EGUs, which included all types of EGUs, and its final definition of “startup” 

adequately balance commenters’ concerns with the requirements of CAA section 112. Responses to the 

specific issues raised by commenters may be found elsewhere in this document.

3.3 Multiple APCDs
126

Comment 121: Commenter 20390 indicates the complicating factor (for multiple APCDs in series) is 

that SCRs, wet FGD, and dry FGD can be operational at different times during the startup cycle, and 

each technology’s design characteristics mandates different operating conditions that cannot be 

singularly defined that the entire plant has completed startup.

Commenter 20390 states that the impact on emissions and APCD operations is not directly related to the 

use of startup fuels, steam flow, or synchronization to the grid. APCD systems’ ability to function and 

operate is based on flue gas temperature and volume flow.

Commenter 20390 states coal plant startups are either warm startups or cold startups, and shutdowns are 

either normal shutdowns or emergency shutdowns. Commenter notes the duration of startup is 

dependent on the speed the system can brought up in temperature without causing thermal stress. 

Commenter states that facilities sync to the grid after certain temperatures are reached in the steam 

turbine, and notes the operator cannot put load on the generator until the EGU is synced to the grid so as 

soon as there is load on the generator (for example, >1 MW), the EGU can be assumed to be on-line. 

Commenter notes that at certain plants, coal firing can begin following the sync to the grid which is 

usually no more than 20 minutes after syncing; other plants require higher loads before firing coal.

Commenter states startup fuel is continued until a certain number of coal mills are brought into service

and that at some plants the startup fuel is co-fired and continues till 1/2 load and at other facilities it 

continues till 2/3 load. Commenter indicates that the capacity of each plant is different as to its ability to 

burn an auxiliary or startup fuel – some plants only have igniters and can burn startup fuel only to about 

10 percent of the design heat input whereas other plants have fuel burners that can burn auxiliary fuel up 

to full load. Commenter states, therefore, that it may not be possible at every plant to bring the system 

up to temperature with clean burning startup fuel and to bring APCDs into service prior to firing coal.

Commenter 20390 provides a summary table of typical startup procedures for multiple APCDs for warm 

and cold startups, see Table 1. 

Table 1. Typical Startup Procedures (Commenter 20390).

APC 

Equipment Warm Startup Cold Startup

SCR 

Require minimum temperature 

(independent of load or duration) prior 

to ammonia injection 

Require minimum temperature 

(independent of load or duration) prior 

to ammonia injection 

SNCR 

Require minimum temperature 

(independent of load or duration) prior 

to ammonia injection 

Require minimum temperature 

(independent of load or duration) prior 

to ammonia injection 

Wet FGD No minimum requirements prior to 

startup 

No minimum requirements prior to 

startup 

Spray 

dryer/baghouse 

Require minimum temperature and flue 

gas flow prior to lime slurry spray. 

Some emissions can be maintained with 

baghouses prior to slurry injection 

Require minimum temperature and flue 

gas flow prior to slurry spray. Some 

emissions can be maintained with 

baghouses prior to slurry injection 
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CDS/baghouse 

Require minimum flue gas flow prior to 

lime injection and require minimum 

temperature prior to water spray. Some 

emissions can be maintained with 

baghouses prior to additional lime and 

water injection 

Require minimum flue gas flow prior to 

lime injection and require minimum 

temperature prior to water spray. Some 

emissions can be maintained with 

baghouses prior to additional lime and 

water injection 

DSI or carbon 

injection system 

Require minimum flue gas flow prior to 

sorbent injection. 

Trona and SBS systems require 

minimum temperature. Do not inject 

carbon while firing oil 

Require minimum flue gas flow prior to 

sorbent injection 

Trona and SBS systems require 

minimum temperature. Do not inject 

carbon while firing oil 

Baghouse Pre-coating of bags required prior to 

startup 

Pre-coating of bags required prior to 

startup 

ESP Energize when flue gas temperature 

>250 °F 

Energize when flue gas temperature 

>250 °F 

Response to Comment 121: The EPA believes that the revised definition of “startup” discussed 

elsewhere in this document adequately addresses commenter’s concerns. We would also note that the 

definition of “startup” does not specifically relate to the terms “cold startups” or “warm startups;” rather, 

it is tied to the initiation of firing of fuel following a period where no fuel had been fired through the 

language “first-ever firing of fuel in an EGU for the purpose of producing electricity or useful thermal 

energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes or the firing of 

fuel in an EGU for any purpose after a shutdown event.” Sources that are starting a cold or warm EGU 

may have to combust additional clean fuels alone for a longer period of time to comply with the final 

work practice; this may require augmentation of their clean fuel capacity. Responses to the specific 

issues raised by commenters may be found elsewhere in this document.

Comment 122: Commenter 20408 states that the EPA should reassess the proposed requirement to 

“vent emissions to the main stack and operate all control devices necessary to meet the operating 

standards that apply at all other times under the final rule ...” to recognize for some boiler types (i.e.,

cyclones) that although the APCD will be activated it may not be at its normal operating level of control. 

Response to Comment 122: The EPA has addressed the issues related to startup earlier in this 

document and ESP use in section 3.0 of this document. Further, we believe that the revised definition of 

“startup” addresses the remainder of commenter’s concerns. We have noted elsewhere in this document 

that the goal of the analysis was to identify the approximate time it took, on average, to initiate operation 

of APCDs by the top performing 12 percent of EGUs to determine the appropriate end for startup – a 

time at which we are confident sources will be able to accurately monitor their emissions using CEMS. 

The goal was not to seek the time it took for APCDs at all EGUs to become operational, nor do sources 

have to engage all of their control devices at the end of startup. Instead, sources are required to comply 

with the numerical emissions limits in whatever manner the source determines is appropriate. The EPA 

believes that the variability contained in the numerical limits is sufficient to include all periods of EGU 

operation, including startup and shutdown. We further note that the 30-day rolling operating day average 

provide EGUs with additional flexibility to meet the emission limits using CEMS, and sources can also 

continue to use clean fuel if they want an additional compliance margin.
128

3.4 Acid Gas APCDs

Comment 123: Commenter 20427 states acid gas APCDs at pulverized coal EGUs are not temperature 

dependent and can meet the MATS’ numeric limits over a wide variety of temperatures and loads.

Commenter states that basic acid gas APCDs can meet the numeric limits over a wide variety of 

temperatures and loads, and there is no basis for further exempting EGUs from compliance with those 

limits. Commenter notes that scrubbers are routinely designed without bypass and are operational at all 

loads, and that DSI improves capture at low temperatures. Commenter states that the MATS’ acid gas 

limits do not require either DSI or scrubber systems to operate at the upper ranges of those technologies’

abilities. Commenter states that complaints that scrubbers may be affected by weather conditions, 

resulting in stack corrosion, can be addressed by using liners for wet gas.

Response to Comment 123: The EPA is not exempting sources from HAP emissions reductions 

requirements as the commenter states. The EPA maintains that its analysis of the startup practices of the 

top performing 12 percent of EGUs, which included all types of EGUs and APCDs, and its final 

definition of the end of “startup” adequately balances commenter’s concerns with the requirements of 

CAA section 112. Responses to the specific issues raised by commenters may be found elsewhere in this 

document.

3.4.1 Wet flue gas desulfurization – wet FGD

Comment 124: Commenter 20387 notes that FGD EGUs are placed in service once the EGU reaches 

stable operation with coal. Commenter notes that past experience with placing the FGD EGUs in service 

while firing fuel oil resulted in fouling of the FGD tower and required the entire liquid level to be 

removed and replaced. Commenter maintains that this operating history requires the FGD to be placed 

into service once the EGU has reached “Stable Operation with Coal”.

Commenter 20390 states wet FGD systems are capable of maintaining SO2 emissions during startup and 

shutdown periods. Commenter states that wet FGD EGUs have fiberglass or plastic components that 

must be protected against high gas temperatures (i.e., approximately 220 °F). Commenter states one or 

two of the lower spray headers must be turned on once the manufacturer’s maximum temperature 

guideline is reached regardless of whether auxiliary fuel or coal is being burned. Commenter states a 

minimum number of recycle pumps must be in service at low load to protect against down draft slurry.

Commenter 20425 states that EGU start-ups from outages where wet FGD maintenance occurs and 

recycle tanks are drained may require an extended period of time to establish suitable scrubber 

chemistry, particularly, alkalinity, to minimize SO2 emissions. Commenter notes that although limestone 

forced oxidation (LSFO) systems can reach suitable alkalinity levels very quickly after start-up, 

magnesium-lime (mag-lime, Mg-lime) systems require much longer time periods to establish suitable 

alkalinity, up to 12 hours for some EGUs, and to establish the proper levels of liquid phase magnesium 

and sulfite.

Response to Comment 124: Responses to these comments can be found above.

3.4.2 Dry FGDs and CFBs
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Comment 125: Commenter 20409 states that for EGUs with dry FGD systems and ash recycling, the 

startup time following planned outages required to introduce coal fuel ranges from about 6 hours for 

unplanned hot restart events to as many as 32 hours for major scheduled outages. Commenter states that 

that depending on the scrubber system installed, from 6 to 18 hours may be required to achieve 

sustainable SO2 reductions once coal fuel is introduced and the necessary flyash has been collected. 

Commenter adds, although not specifically identified in the EPA’s Startup TSD, cooperatives with CFB 

boilers equipped with SNCR for NOx reduction would have similar concerns if, for example, NOx 

compliance obligations commence when the proposed HAP SSM startup ends.

Commenter 20410 states that the Startup TSD indicates that the EPA found no significant difference in 

performance related to startup events between the different boiler types and APCD technologies 

assessed in the analysis. Commenters 20409, 20410, and 20423 state that, although not specifically 

discussed in the narrative, the data in Figure 16 of the EPA’s Startup TSD show a distinct difference 

between dry and wet FGD SO2 emissions rates as a function of hours after start after generation for 

subcritical EGUs. Commenters state that although not identified in the EPA’s Startup TSD, it believes

there are subcategories of EGUs within the subcritical dry FGD group that will frequently take a 

significantly longer time to reach normal operation regarding SO2 emissions reductions. Commenter 

20410 states that, in fact, Figure 16 shows that 6 hours after the start of generation, SO2 emissions with a 

dry FGD are still approximately twice the MATS alternate SO2 limit while the wet FGD shows 

emissions below the MATS alternate SO2 limit throughout the startup. Commenter 20410 adds that 

Figure 16 shows the average SO2 rate, so presumably there are values below and above the line shown 

in Figure 16. Commenters 20409 and 20423 state that subcritical EGUs utilizing ash recycling for 

proper dry FGD function clearly fall into one of these subcategories because additional time is needed to 

collect the flyash necessary to properly prepare and mix the slurry for proper FGD function. 

Commenters 20409 and 20423 state that, for example, should subcritical EGUs with dry FGDs that 

utilize ash recycling be required to demonstrate SO2 emission compliance at the point in time coinciding 

with the end of startup as proposed for HAP SSM, many may likely encounter SO2 compliance 

problems. Commenter 20409 states that to be clear, these EGUs would not encounter SO2 compliance 

issues following their currently permitted startup procedures and requirements. Commenter 20409 states 

that dry FGD SO2 emission rates may not reach anything close to normal expected operating levels until 

approximately 18 hours after generation start, whereas wet FGD performance appears to reach 

anticipated operation almost immediately after generation commences. Commenter 20423 states that the 

startup time following planned outages required to introduce coal fuel ranges from about 6 hours for 

unplanned events to 1 or 2 days for major scheduled outages.

Commenter 20410 states that because it is more common to use dry FGD on lower sulfur coals and wet 

FGD on higher sulfur coals, the average SO2 emission rate at 6 hours after start of generation and 

beyond likely includes data where the dry FGD control device has not been engaged and shows that 

there is likely an even bigger difference in the time it takes to bring a wet FGD on-line versus the time it 

takes to bring a dry FGD on-line during startup.

Commenter 20409 thinks subcritical EGUs that utilize dry FGDs and ash recycling for SO2 control and 

EGUs that utilize CFB combustion with SNCR for NOx control comprise two subcategories that would 

not be able to meet SO2 and NOx compliance obligations under the HAP SSM startup proposal. 

Commenter suspects there are other EGU subcategories where EGUs would be unable to meet non-HAP

emission compliance obligations immediately after the proposed HAP SSM startup ends.
130

Comment 126: Commenter 5831 states that the EPA should modify its technical document to include 

discussion about the use of recycle flyash in an FGD and analyze the hot/cold startup impacts separately 

and then modify the conclusions and the definition of startup accordingly. Commenter states that 

although the use of recycle flyash does not matter significantly for a hot restart, there is no recycle 

flyash available to fabricate a slurry mix for several hours after a cold restart. Commenter notes that the 

EPA analysis somewhat addresses this, but the impact is masked by averaging hot and cold restarts 

together. Commenter states that there are subcategories of EGUs within the subcritical dry FGD group 

that will always take a significantly longer time to reach normal operation regarding SO2 emissions 

reductions. Commenter states that EGUs with dry FGDs that utilize ash recycling may likely encounter 

SO2 compliance problems if they are required to demonstrate SO2 emission compliance at the time the 

proposed SSM startup ends. Commenter notes that a recent extraordinary startup of its Holcomb Unit 1 

(H1) EGU, following the installation of new over-fire air and low NOX burners, required 32 hours of 

low-load coal operation before sufficient flyash was available to enable the normal operation of the dry 

FGD systems. Commenter maintains that the EPA needs to modify the Startup TSD to include this 

discussion and analyze the hot/cold startup impacts separately and then modify the conclusions and the 

definition of startup accordingly. Commenter indicates that its H1 EGU does not now encounter any SO2

compliance issues, following current permitted startup procedures, or with any other compliance 

limitations or requirements.

Commenter 5831 states that the startup time following planned outages required to introduce coal fuel 

ranges from about 6 hours for unplanned events to as many as 32 hours for major scheduled outages. 

Commenter notes that, although not specifically discussed in the Startup TSD, the data in Figure 16 

show a distinct difference between dry and wet FGD SO2 emissions rates as a function of hours of start 

after generation for subcritical EGUs. Commenter indicates that following a cold restart, its H1 EGU dry 

FGD SO2 emission rates do not reach normal expected operating levels until approximately 18 hours 

after generation start. Commenter states that its data show false starts can and do exceed the time 

proposed to end startup under unexpected and unavoidable circumstances. Commenter provides 

attachments with information from commenter’s experience.

Commenter 5831 states that, as noted by the EPA, the normal progress of startup activities may involve 

the cessation of fuel combustion following the initial combustion of ignition or startup fuel. These 

interruptions may include planned multiple stop/starts (which may include establishing stable igniter 

operation and flame safety safeguard systems, proof of boiler and/or turbine interlocks, chemical 

cleaning operation, initial turbine warming, turbine shakedown operations including those for safety and 

insurance purposes) of the combustion process, and unplanned, but nevertheless necessary, cessations in 

the same combustion process (which may include sudden and unexpected flame stability problems; 

temperature and/or pressure excursions; unavoidable operational equipment problems with fans, air 

heaters, and pumps, for which normal stable expected operational ranges have not been achieved; and 

unexpected tube leaks which may take multiple days to repair). Commenter alleges that in the 

experience of its members, these interruptions range in duration from a few hours to multiple days.

Commenter 5831 cites to a number of examples for its H1 EGU. Commenter indicates that there were 

four occasions within the 2-year EPA analysis of startups (2011-2012) where an H1 startup sequence 

was interrupted between one and three times before it reached normal operation. Commenter states that 

these interruptions ranged between 1 hour and 4 hours; in all but one case, the events arose before coal 
131

fuel had been established. Commenter notes that in a separate prolonged shutdown situation following 

an EGU trip while using natural gas fuel, an exhaustive troubleshooting exercise was conducted to 

isolate an electrical problem on the plant control system; a 2-day effort was required to rectify the 

problem once the source was identified. For the examples cited, commenter indicates that stable dry 

FGD operation was achieved between 2 and 27 hours following stable coal firing.

Response to Comment 126: The EPA maintains that its analysis of the startup practices of the top 

performing EGUs, which included all types of EGUs, and its final definition of “startup” adequately 

balance commenter’s concerns with the requirements of CAA section 112. To the extent the commenters 

believe that the work practice must be achievable by all sources without cost, we disagree for the 

reasons stated above. The EPA would note that sources are not required to comply with the alternate 

SO2 emission limits at the conclusion of startup but, rather, can comply with the HCl emission limits. 

Further, commenter notes that some/many of the startup interruptions occurred prior to the firing of coal; 

however, commenter does not indicate whether electricity generation had begun. The final definition of 

the end of “startup” is triggered by the start of electricity generation. In any case, if no coal has been 

combusted, the EGUs could shut down and reinitiate startup on clean fuel alone and be in compliance 

with this final rule. The inherently low HAP content of the clean fuels will thus greatly reduce the HAP 

emissions associated these types of startup events.

Comment 127: Commenter 20390 states dry FGD systems may include SDA and CDS (to include 

Novel Integrated Desulfurization System, NIDS) and these systems typically include an absorber vessel 

followed by a baghouse. Commenter states that neither system can be operated with slurry or water 

addition at low temperatures because of the potential corrosion in the ductwork and baghouse. 

Commenter states a minimum flue gas flow and temperature must be maintained for SDA to prevent 

lime slurry buildup on the absorber vessel walls, which may cause structural damage or plugging in the 

vessel. Commenter states SDA lime slurry controls are not turned on until a minimum of 250 °F and 50 

percent of design flow, although PM removal can be maintained during startup and shutdown periods. 

Commenter states that CDS lime can be injected during startup as soon as lime can be suspended in the 

absorber vessel, and water can be injected when the flue gas reaches 180 °F dependent on flue gas 

properties. Commenter states flue gas flow is normally required to be approximately 50 percent of 

design flow, and can operate at 25 percent with flue gas recirculation. 

Response to Comment 127: See above for responses to technical and legal concerns identified in these 

comments. Under the final reconsideration startup and shutdown requirements, operators do not have to 

engage any controls within a specified time period (other than PM controls which must be engaged 

within 1 hour of firing of coal, residual oil, or solid oil-derived fuel); rather, they are only responsible 

for meeting the numerical emission limits no later than 4 hours after electricity generation. The use of 

clean fuels to the maximum extent possible will assist in heating the system to allow the APCD 

equipment to get to operating temperatures.

Comment 128: Commenters 20390 and 20410 state that DSI effectiveness is dependent on flow 

distribution and operating temperature; flue gas flow required is normally approximately 50 percent of 

design flow (possibly 25 percent using flue gas mixing), and some sorbents require minimum flue gas 

temperatures (e.g., 250 or 290 °F). Commenter 20410 states that the downstream PM control device 

needs to be engaged to capture the DSI reaction products and unreacted sorbent to minimize emissions 

of PM.
132

Commenter 20424 believes that the standards should also be revised to allow the recognition of the 

constraints of application of DSI, which should be revised to allow the start of DSI after appropriate 

temperature is reached. 

Response to Comment 128: We address technical concerns above.

Comment 129: Commenter 20424 states that the proposed revised standards would allow limestone 

injection to begin after appropriate temperatures have been attained in FBC EGUs that inject limestone 

for acid gas control and allow SNCR, SCR, and dry scrubber systems to start as soon as technically 

feasible after the appropriate temperature has been reached.

Commenter 20427 states that although acid gas emissions at CFB EGUs using limestone injection can 

be temperature dependent, that provides no basis to exempt boilers from Hg and PM standards because 

APCDs for those pollutants can be used at low temperatures for both pulverized coal and CFB boilers. 

Commenter states that temperature constraints on acid gas APCDs at CFBs do not justify time or loadbased exemptions, as the EPA’s analysis demonstrates there is no reliable correlation between the 

number of hours elapsed or electricity generation and the achievement of the temperature needed for 

acid gas control. Commenter states that if an exemption to compliance is added for acid gas limits at 

CFB EGUs, the exemption should be temperature dependent, e.g., numeric standard applies when boiler 

temperature exceeds 1500 °F.

Commenter 20433 rebutted by stating that Commenter 20427 misunderstands CFB operation. 

Depending on where a thermocouple is located, Commenter 20433 maintains that a CFB EGU could 

record a 1500 °F “boiler” temperature from just an oil burner although scarcely having begun the startup 

cycle. As Commenter 20433 explained in EPA-HQ-OAR-2009-0234-20180 and in EPA-HQ-OAR2011-0044-5794, in an FBC EGU, if lime is added too early in the startup sequence, the flame will be 

extinguished. Commenter 20433 notes that FBC EGUs that inject limestone must reach a minimum bed 

temperature of approximately 1500 oF for the limestone to calcine, and thus become effective at 

reducing acid gases; FBC EGUs often burn coal for about 45 minutes before lime is added and then

additional time is required before the bed chemistry stabilizes (i.e., the pollution control is fully 

effective). Commenter 20433 states that normally, the bed is stable and up to temperature when 40 

percent load is reached.

Commenter 20425 states that for FBC EGUs, if limestone is added too early in the startup sequence, the 

flame will be extinguished and that FBC EGUs that inject limestone must reach a minimum of 

approximately 1500 °F for the limestone to calcine, and, thus, become effective at reducing acid gases. 

Commenter notes that FBC EGUs often burn fuel for about 45 minutes before limestone is added and 

that additional time is then required before the bed chemistry stabilizes; normally, the bed is stable and 

up to temperature when approximately 40 percent load is reached. Commenter recommends that the 

EPA should define “startup” for FBC EGUs as 3 hours after the bed temperature reaches 1500 °F; an 

alternative would be 4 hours after 25 percent load is first achieved, or 12 hours after first electricity 

generation, whichever occurs first.

Response to Comment 129: See responses to comment above for responses to these comments. In 

addition, the EPA notes that the requirement to maximize the use of clean fuels during the startup period 
133

will assist in getting the EGU and the associated APCD equipment up to proper operating temperatures 

while minimizing emissions of HAP. EGUs are required to engage PM controls within 1 hour of 

addition of coal, residual oil, or solid oil-derived fuel and the startup period will end 4 hours after the 

generation of electricity or creation of useful thermal energy, at which time the numerical emission 

limits must be met.

3.5 PM control

Comment 130: Commenter 20393 states that the Startup TSD only focuses on the startup of SO2 and 

NOx control devices and does not address the startup of ESP and other PM control devices. Commenter 

states that the startup of PM control devices should also have been included in analysis in order to assess 

the startup issues unique to ESPs. Commenter states that the analysis only provides an assessment as to 

when coal-fueled EGUs, on average, will be able to bring online their APCDs and, as a result, fails to set 

a specific time frame in which it is feasible to start up and operate all APCDs in a safe and efficient 

manner.

Commenter 20418 states that the EPA’s analysis does not consider the impact of PM control devices on 

an EGU’s ability to meet the MATS limit during startup. Both of commenter’s coal-fired EGU plants 

use hot-side ESPs to control PM emissions. Commenter notes that these HS-ESPs are designed to collect 

fly-ash when the resistivity is below a certain threshold, typically occurring at temperatures in excess of 

550 °F and operation of the hot side ESPs below these temperatures can diminish the collection 

efficiency of the equipment. Commenter maintains that this is an important consideration in determining 

the appropriate definition of startup for a rule that incorporates PM emission limitations as a compliance 

option.

Commenters 5833 and 5834 state that alternative fuels are used during startup that emissions control 

equipment is not designed to target. Commenters state that the EPA’s Startup TSD omits pollutants 

other than NOX and SO2 and omits APCDs for pollutants other than for NOX and SO2 and did not 

address the startup of ESP and baghouses. Commenters state that startup of PM control devices should 

also have been included in analysis in order to assess the startup issues unique to those devices. 

Commenter 5834 notes that as it and other commenters have demonstrated, similar to the pollution 

controls for NOX and SO2, pollution controls for PM cannot safely be engaged at first firing of coal due 

to a minimum operating temperature necessary for their safe and reliable operation and that although its 

ESPs are engaged at the “end of startup,” as per the discussion in the June 25, 2013, notice, the ESPs 

cannot safely be engaged at first firing of coal due to a minimum operating temperature necessary for 

their safe and reliable operation. Accordingly, Commenter 5834 maintains that the work practice 

standards should except ESPs and associated ACI engagement similar to the exception provided for 

other APCDs.

Commenter 5833 states that fuel oil is the main startup fuel for its coal fired plants. Commenter alleges 

that manufacturers of its emission control devices have stipulated that primary particulate emissions 

equipment (baghouses and ESPs) not be put into service when burning fuel oil at low temperatures as 

fuel oil coats bags in a baghouses and destroys a bag’s ability to collect flyash (baghouses have to be 

bypassed during startup for this reason). Commenter also maintains that manufacturers also do not 

recommend energizing an ESP until certain minimum temperatures are obtained or the plates in a 

precipitator will get coated with fuel oil residue and impact their ability to collect flyash.
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Commenter 5834 submits that coal-fired EGUs like its Units 1, 2, and 3 that are equipped with ESPs 

cannot be safely engaged immediately once firing converts to coal without risking significant equipment 

degradation or, worse, an explosion. Commenter notes that all three of its EGUs use a “clean fuel” (No. 

2 fuel oil) during all startup and shutdown procedures – during startups, fuel oil is usually fired for 

several hours; however, for cold startups, when the EGU has been off line for more than 95 to 100 

hours, it is not uncommon for fuel oil to be fired for up to 20 consecutive hours. Commenter maintains 

that this extended oil firing is needed to match steam temperature to turbine metal temperature and 

prevent catastrophic damage to major equipment components. Commenter notes that while firing on fuel 

oil, the steam turbine is rotated and synchronized (i.e., power is provided to the grid), yet the ESP 

remains off-line until at least one coal feeder reaches 50 percent of its capacity; at that time, multiple 

fields in each chamber of the ESP are energized and fuel oil use begins to decrease. Commenter states 

that the ESP fields are not energized during the initial startup procedure in order to allow sufficient time 

for flue gases passing through the ESP to preheat the ESPs prior to energizing – otherwise, if the ESP is 

operated at or below the dew point (approximately 180 to 200 °F), an oil or moisture coating forms a 

cemented dust layer (crusted coating) on the collection plates which impedes proper operation. 

Furthermore, commenter notes that for EGUs, such as the ones it has, that are started up on distillate fuel 

oil, the ESP is not energized until coal firing is established so as to prevent the possibility of explosions 

due to oil carry over or ignition of unburned carbon or other combustible gases. Commenter asserts that 

the prevention of fires and explosions in the ESP is critical to the safety of plant personnel and 

equipment, and is also consistent with good engineering practice. Commenter provides several 

attachments concerning ESP engagement during startup required to ensure safe and reliable operation

consistent with manufacturer recommendations. Commenter alleges that because it is not 

technologically feasible to operate its ESPs before a safe operation temperature is achieved, and, 

therefore, commenter respectfully requests that the EPA adopt its proposed changes to the work practice 

standards to address ESPs and associated ACI.

Commenter 5834 cites to a manufacturer recommendation for its Unit 3 that states:

As the first mill for coal firing is brought on line and flue gas temperature increases to 

approximately 200°F, a two (2) hour delay is recommended prior to precipitator 

energization. This will allow sufficient time for flue gases passing through the 

precipitator chambers to pre-heat the internals prior to energizing the transformer/rectifier 

sets. Operation at or below dew point may cause a crusted coating to form on the 

collecting electrodes which will impede proper operation.

Similarly, for its Units 1 and 2 Commenter 5834 provides from the operations manuals:

Allow sufficient time for flue gases passing through the precipitation chambers to preheat 

the internals prior to energizing the T/R sets to insure operation of the precipitator above 

dew point. Operation at or below dew point may cause a crusted coating to form on the 

collecting electrodes which will impede proper operation. A thumb rule of 1 hour of deenergized operation for every 100 °F of normal flue gas temperature is satisfactory.

Commenter 5834 notes that the oil igniters for its Units 1, 2, and 3 were not designed to preheat the ESP 

plates without additional heat provided by the combustion of coal; the oil igniters were designed solely 
135

to light the fuel and provide flame stabilization and are not large enough to provide sufficient heat to 

reach the minimum safe and reliable operating temperature in the ESPs regardless of how long the oil 

igniters are fired.

Commenter 5840 states that some ESPs cannot reach safe startup temperatures on startup fuel no matter 

how long it could be burned; these ESPs require coal firing to achieve a safe startup temperature. 

Commenter recommends that the EPA include ESPs in the list of APCDs that do not have to be in 

service when first tiring coal.

Commenter 20387 states ESPs must be placed into service after the EGU is on-line with one coal mill in 

service. Commenters 20387 and 20410 state the original equipment manufacturer (OEM) does not 

recommend placing the ESP in service until fuel oil is no longer required to startup the boiler; the fuel 

oil may cause fields to spark and ignite, leading to fires that may damage equipment and place plant 

personnel at risk. Commenter 20387 maintains that this, therefore, requires the ESPs to be placed into 

service after the EGU is put on-line with one coal mill placed in service.

Commenter 20390 states that startup and shutdown are critical periods for ESP operation that can have a 

direct impact on achieving performance and maintaining this performance. Commenter states two main 

concerns: operating the ESP below the acid dewpoint and spontaneous combustion or explosion of 

unburned combustibles that could be ignited by sparking. Commenter states ESPs should not be 

energized until the flue gas temperature is above the acid dewpoint, to avoid moist ash particles 

collecting on electrodes and hopper walls forming a damp sludge that is difficult to remove. Commenter 

states when this buildup of material is dried upon reaching normal operating temperature, it can form 

hard crusty deposits cemented to the electrodes and hoppers, which cannot be dislodged with rapping, 

and reducing the ESP performance. Commenter states during startup, the damp ash can create wet 

conductive coating on surfaces of high voltage support and anti-sway insulators, leading to short circuits 

and potential failure of the insulators. Commenter states SO3 formed in the boiler reacts with moisture to 

create sulfuric acid vapor that condenses below the acid dewpoint temperature. Commenter states

sulfuric acid dewpoints vary depending on the coal type, and range from approximately 276 to 326 °F 

without SCR and from 289 to 340 °F with SCR (SCR may increase the sulfuric acid dewpoint 

temperature by 10 to 20 °F depending on SO2 to SO3 conversion in the SCR). Commenter states ESPs 

are typically not energized for 30 minutes after stable flame has been achieved to avoid hazardous 

conditions. Commenter states there is potential for carbonaceous material, CO, or unburned fuel during 

startup caused by incomplete combustion, and there is also excessive O2 in the system, which could 

cause spontaneous combustion or even an explosion, particularly if there is sparking in the ESP with the 

ESP energized. Commenter states that CO is extremely unstable so that general flammability limits are 

considered as explosion limits and that excessive carbonaceous ash (high LOI) production can lead to a 

fire of the dust collected on the ESP collecting plates and/or ESP hoppers when excessive oxygen levels 

are present in the flue gas during boiler startup – the ignition source in the ESP is sparking between 

electrodes. Commenter states applications with higher probability of fires include wood waste boilers, 

oil fired boilers, and coal stoker fired boilers.

Commenter 20408 states that introducing SO3 (to reduce the ash resistivity and improve ESP collection 

efficiency) too early in the startup process will cause corrosion in the duct work and ESP because of the 

lower temperatures during startup. Introduction of SO3 may not be possible until 50 percent load is 

achieved where temperatures are high enough to prevent corrosion.
136

Commenter 20401 states that the startup definition also fails to acknowledge certain particulate controls 

such as ESPs or fabric filters also have operational constraints during startup. In the case of an ESP, 

Commenter maintains that after purging the boiler there are manufacturer recommended minimum 

temperature and moisture requirements that must be met before energizing the ESP – operating at or 

below saturation temperature can lead to arcing inside the ESP, a safety hazard, and can cause crust to 

form on the collector surfaces, which will result in reduced performance; in the case of a baghouse, 

during startup when combusting distillate fuel oil (included in the EPA’s list of approved “clean fuels”) 

resulting constituents in flue gas can foul and damage the bag material, leading to a higher risk of bag 

failure and reduced overall performance.

Commenter 20267 states that in the listing of exceptions to the mandatory control device operating 

requirement, no mention was given to ESPs or baghouses, which, like SCRs and SNCRs, must achieve 

the appropriate temperature before being placed in service as well as FGDs, which must operate only 

after the upstream PM controls are in service. Commenter asks the EPA to include the ESP and FGD 

Systems in the listing of the pollution control exceptions.

Commenter 20289 states that prematurely starting an ESP risks significant equipment degradation 

caused by cemented dust on the ESP collection surfaces or an explosion. Commenter states that a 

November 16, 2012, the EPA memo (“Startup and shutdown provisions”) appears to provide some 

clarity. Commenter states that when responding to concerns regarding minimum stable load and the 

efficient stable and safe operation of air pollution controls, the EPA, although concluding that petitioners 

have not provided data supporting this claim, suggests that operators can remain compliant by co-firing 

with clean fuel. Commenter states that by advocating co-firing of clean fuels after startup ends as an 

appropriate means to achieve compliance, the EPA is recognizing the limitations of certain pollution 

controls and acknowledges that once startup ends, compliance is based on meeting emission limits, not 

work practice standards. Commenter described the startup procedures at EGUs equipped with ESPs 

where the ESPs cannot be brought online until certain operating conditions are attained.

Commenter 20415 supports refinements to the requirements for engagement of APCDs on EGUs. 

Commenter states that these changes reflect the concerns raised by commenters. Commenter states that 

however, two important additional refinements are needed. Commenter states that first, the rule should 

include this clarification in italics: “as expeditiously as possible but not before appropriate boiler 

conditions are achieved and APCDs are online.” Commenter states that the second refinement needed 

regards ESP operation on coal-fired EGUs, which is similar to ESP operation on coal-fired ICI boilers 

from a safety perspective. Commenter states that specifically, there are fire and explosion hazards with 

energization of an ESP when unburned fuel may be present and the O2 level in the flue gas is high 

enough that the mixture can be in the flammable range. Commenter states that the EPA needs to 

reconsider this safety issue and revise the requirements to include ESP energization with the other 

controls that are to be started as expeditiously as possible rather than when solid fuel firing is first 

started.

Commenter 20393 states that the EPA should note that the use of oil and coal during startup is not 

binary, but rather operates on a continuum. Commenter states that under usual operating conditions, the 

igniter fuel is not completely removed when coal is introduced, but remains a part of the fuel mix as the 

EGU reaches proper temperatures. Commenter states that the ESP plates become covered in an oily 
137

residue that decreases the effectiveness of the ESP and creates a safety risk because of potential sparking 

and unstable combustion.

Commenter 20393 states that it is necessary to refrain from operating the ESP until the EGU has 

continuously combusted coal for a period of about 3 hours. Commenter suggests that affected coal-fired 

EGUs should not be required to place their ESPs into service until coal has been continuously 

combusted for 3 hours and the ESPs have reached safe minimum temperatures in order to prevent fires 

and/or explosions within the precipitators. Commenter maintains that the EPA has, in fact, previously 

recognized that in some facilities it is necessary to provide additional time after coal is continuously 

burned to safely engage an ESP. Commenter alleges that this approach is consistent with its 2004 

Consent Decree with the EPA and the South Carolina Department of Health and Environmental Control, 

which states in paragraph 89 that:

...shall continuously operate each ESP in the...System at all times that the Unit it serves is 

combusting Fossil Fuel, except that...need not commence operation of any ESP until the

Unit that the ESP serves has continuously combusted any amount of coal or petroleum 

coke for a period of two hours (three hours for Units at the Winyah Plant and at the 

Jefferies Plant)...shall use good engineering practices for PM control at all times that the 

Unit is combusting Fossil Fuel.

In addition, commenter maintains that the 2003 consent decree between Virginia Electric and Power 

Company (VEPCO) and the EPA contains a similar provision in paragraph 78, which states in pertinent 

part:

Commencing within 30 days after lodging of this Decree, VEPCO shall operate each ESP 

and baghouse within the VEPCO System to maximize PM emission reductions through 

the procedures established in this Paragraph. VEPCO shall (A) commence operation no 

later than two hours after commencement of combustion of any amount of coal in the 

controlled System Unit, except that this requirement shall apply to Bremo Power Station 

Units 3 and 4 commencing two hours after cessation of oil injection to the boiler, and 

provided that, for all ESP-equipped Units, “combustion of any amount of coal” shall not 

include combustion of coal that is the result of clearing out a Unit’s coal mills as the Unit 

is returned to service.

Commenter 20393 states that the work practice requirement will not be technically feasible for many 

coal-fueled EGUs with ESPs and could pose unnecessary safety risks to the operation of the ESP.

Commenter notes that early in the implementation of the CAA, the EPA issued a manual on “Operation 

and Maintenance of Electrostatic Precipitators,” which discussed the safe use of an ESP and specifically 

its temperature and dewpoint requirements. The manual states:

...when and how much of the ESP should be energized is a much-debated topic in many 

applications. Many believe that energization should not be attempted until the moisture 

dewpoint has been exceeded for several hours, and some like to wait until the acid 

dewpoint temperature has been surpassed, to avoid excessive sparking and the minimize 

buildup on the ESP internals. Newer, modern, power supplies, however, should be able to 

energize the ESP with little or no sparking, whereas older controllers probably should be 
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set in manual control below the spark threshold. The concern with sticky particulate and 

sparking is two-fold. At best, if the sticky particulate fuse or clinker on the plates and 

wires, the ESP will have to be shut down and washed out. At worst, unstable combustion 

could lead to unburned carbon, hydrocarbons, and CO in the ESP, which may be set afire 

or result in an explosion that endangers personnel and could also permanently destroy the 

ESP’s performance potential. Substantial misalignment can occur within an ESP as a 

result of a fire or explosion. Because of the tendency for an ESP to spark during startup 

and provide a possible ignition source, some plants have approached the explosion 

potential by lengthening their startup times.

Commenter indicates that it is its understanding that a lengthened startup time as discussed in the 

manual would include the use of both a clean fuel and coal, to get the facility up to the correct 

temperature to engage the ESP safely.

Commenter 20393 urges the EPA to add ESPs to the list of APCDs (such as SNCR, SCR and dry 

scrubber systems) that need not begin operation until it is technically feasible and safe to do so as 

the same flexibility afforded these APCDs is warranted for ESPs also. Commenter states that if 

the EPA decides not to make an exception for ESPs, then the work practice standard for 

filterable PM emissions must be revised to accommodate as to when a coal-fired EGU must 

begin to operate its ESP. Commenter suggests that the EPA could not require the operation of the 

ESP until the end of “startup” as defined by the new proposed definition. Commenter alleges that 

this alternative approach could address the technical feasibility problems posed by the current 

work practice requirement for ESPs, provided that the EPA were to make minor refinements to 

that new definition of startup.

Commenter 20393 disagrees that an ESP is not “condition-specific” and that there are no constraints 

with engaging PM controls (ESPs and baghouses), wet scrubber, and sorbent injection systems (ACI and 

DSI) when firing coal, solid oil-derived fuel, or residual oil in EGUs during startup and shutdown. 

Commenter states that the igniters in older boilers are not equipped to properly pre-heat the ESP in a 

reasonable amount of time, and thus there are significant constraints to requiring their operation during 

the startup period.

Commenter 20390 states flue gas temperature has a major effect on ESPs. Commenter states if ESP 

voltage is energized prior to flue gas being above the acid dewpoint temperature, wet ash particles may 

collect on the emitting and collecting electrodes and hopper walls. Commenter states the material is 

difficult to remove with electrode rapping, can form hard crust deposits cemented to electrodes, and 

fouling of electrodes causes reduced collection efficiency.

Comment 131: Commenter 20414 asserts that not all EGUs can engage their emissions controls 

devices, particularly ESPs, upon first generation of electricity or start of coal combustion. Commenter 

states that furthermore, with regard to ESPs, it agrees with those commenters who state that many EGUs 

may not be able to technically or safely engage their controls due to temperature or flow condition 

limitations. Commenter states that additionally, it agrees that operating ESPs at temperatures less than 

temperatures recommended by the OEM could create safety risks. Commenter believes these concerns 

are valid, particularly with regard to ESPs in operation at many Texas EGUs, including some operated 

by its members. Commenter states that these concerns regarding ESPs are well documented in the record 
139

before the EPA, including by environmental lobbying organizations (see EPA-HQ-OAR-2009-0234-

17975). These comments provide that:

Some electrostatic precipitators are not turned on during startup and shutdown, because 

they require minimum temperature for safe operation...The point at which the ESP can be 

brought on-line is dependent on several factors. The most significant factor is inlet gas 

temperature which is in turn related to quantity of fuel burned, fuel quality, how long the 

unit has been offline, etc. This minimum temperature is consistent with that prescribed by 

the control device manufacturer as a preventative measure against failure, explosive 

conditions, and to ensure long term functionality. Id., at 14. (emphasis added).

During periods of startup, shutdown etc., when exhaust gas temperatures are low and 

other gas properties may not be optimum (i.e., its moisture content, etc.), it is quite 

common for ESPs to not be energized until proper operating conditions occur. Id., at 3-4 

of attached referenced testimony of Dr. Ron Sahu.

Based on discussions with various equipment manufacturers and review of operating 

manuals, there are often minimum temperature requirements for ESPs in order to avoid 

issues such as moisture condensation and potential damage (which depend on the type of 

fuel that is used for startup, etc.). Id. at 4. fn 2, of attached referenced testimony of Dr. 

Ron Sahu.

Commenter 20419 states that one member specifically is concerned with its ability to comply with the 

proposed definitions of startup at its coal-fired EGUs that burn low-sulfur coal and use only an ESP for 

emission control. Commenter alleges that the ESPs at these EGUs must be de-energized at all times 

when the flue gas temperature may be below the acid dew point and the ESP also must be de-energized 

during the firing of start-up fuels, such as #2 fuel oil, until coal firing results in volatile gas 

concentrations that are below levels which would pose an explosive hazard in the ESP. Commenter 

indicates that one ESP manufacturer recommends that the ESP remain de-energized during startup until 

flue gas temperatures within the ESP remain above 200 °F for 2 hours resulting in periods during startup 

and shutdown when the EGU is firing fuel while the ESP is de-energized. Commenter states that, as a 

result, during these periods the particulate loading of the flue gas downstream of the ESP can be 

significantly higher than that which is observed while the ESP is in operation. Commenter states that the 

combination of higher particulate loading and low flue gas flow rates results in settling of particles 

within the flue gas ductwork downstream of the ESP and that this settled particulate will remain in the 

ductwork until the EGU load is raised following startup such that the flue gas flow rates cross certain 

threshold velocities upon which re-entrainment will occur and the PM is “swept” into the gas stream and 

emitted through the stack. Commenter maintains that the exact loads/flue gas velocities that correspond 

with re-entrainment is specific to each individual EGU, but in some cases these “duct sweeps” may not 

occur until the EGU is brought to an operating condition at or near full load (corresponding with high 

flue gas velocity) and, depending on market conditions, a EGU may not reach full-load operation within 

the window proposed by EPA for startup. Commenter notes that in these situations, “duct sweeps” will 

occur outside of the prescribed startup period. Commenter indicates that this situation may occur more 

frequently in the future as grid operators work to integrate the growing amount of renewable generation 

into the nation’s grid; the use of intermittent renewable generating sources can cause additional startups, 

shutdowns, or low-load operations for fossil-fueled EGUs. Commenter maintains that the proposed 
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definitions for the end of startup may not allow sufficient time for ESPs to be put into service and reach 

the operating efficiencies necessary to comply with MATS and that the EPA should provide an 

allowance for periods of “duct sweeps” to be excluded from the determination of compliance with 

applicable MATS emission limitations.

Commenter 20419 notes that EPA’s Startup TSD bases its proposed definition of the end of startup on 

implementation times for FGD and SCR, and does not address the startup of baghouses or ESPs. The 

Startup TSD, therefore, does not consider whether units employing baghouses or ESPs would be able to 

comply with the proposed definition of the end of startup.

Commenter 20422 states that the EPA already addressed in the final preamble the issue of ESP 

equipment degradation, explosions, or destruction of equipment.

Commenter 20427 states PM limits can be met without further expansion of the startup exception. 

Commenter states state-of-the-art PM APCDs can be safely and effectively operated at temperatures 

achievable within the scope of the current work practice standard. Commenter alleges that, although it 

recognizes the importance of avoiding safety risks, the operational experience of several plants suggests 

that these concerns are, at best, theoretical. Commenter cites the startup and shutdown minimization 

plan for four EGUs at a power plant that uses fuel oil as the startup fuel and routinely operates ESPs 

during startup and shutdown events. Commenter cites the facility’s plan:

Although the equipment is not fully effective until proper temperatures and stable 

conditions are reached, startup emissions are minimized by placing the electrostatic 

precipitator and flue gas desulfurization scrubber in service prior to the introduction of 

fuel to the boiler. Placing the electrostatic precipitator in service early in the process 

provides for a reduction in particulate matter emissions...

Fuel oil is the initial heat input source used during boiler unit startup, and unit startup 

begins when fuel oil is introduced into the boiler. As the boiler, turbine equipment and 

steam temperatures rise to design values, coal mills (pulverizers) are gradually placed 

into service concurrently with fuel oil firing. (Generally, two pulverizers are operational 

during the end phase of the boiler startup process.) As steam and equipment temperatures 

continue to rise while co-firing on fuel oil and coal, the boiler combustion process 

stabilizes adequately such that fuel oil firing can cease. Startup ends no later than the 

point in time when flue gas temperatures to the electrostatic precipitator reach a 

temperature of 220 °F and two coal pulverizers have been placed into service. Startup 

does not extend beyond 20 hours per startup period.

Commenter 20427 states the operator further notes that these procedures may be safely followed even in 

the face of contrary manufacturer’s recommendations. Commenter states these four EGUs have been 

operated in this manner since approximately 2007 without the safety and equipment difficulties 

hypothesized by industry commenters, and the continued safe operation of these EGUs for years while 

using challenging startup fuel demonstrates the feasibility of ESP operation during startup and shutdown 

provided the ESP is kept clean and properly maintained. Commenter cites opacity data for these EGUs 

that show the benefits of operating PM APCDs through startup, with low to no opacity exceedances, 

suggesting low PM emissions. Commenter cites another 900 MW EGU that is capable of energizing its 
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ESP throughout, and cites a figure from a December 2012 EPA memorandum showing the ESP is 

energized at the beginning of oil fire (startup fuel) in the boiler. Commenter alleges that even if the EPA 

could tailor its standard to a particular (sub-optimal) pollution control – which it cannot, according to 

CAA sections 112(d) and 112(h) – there is thus no practical reason that ESPs cannot be safely operated 

whenever coal is used at an EGU.

Response to Comments 130 and 131: The EPA proposed that:

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions 

to the main stack(s) and engage all of the applicable control devices except limestone 

injection in FBC EGUs, dry scrubber, SNCR, and SCR. (77 FR 71342)

Commenters have correctly interpreted that this proposed language required that ESPs be engaged once 

coal, residual oil, or solid oil-derived fuel firing was initiated. Commenters have raised a number of 

concerns related to operational and safety issues related to the engagement of ESPs this early in the 

process.

The EPA believes that the SO2 and NOX analysis is appropriate for defining the end of startup because 

these are usually the last controls to come on line and they, therefore, serve as a proxy for the end of 

startup, at which point we are confident sources will be able to accurately monitor HAP emissions. The 

fact that we have no HAP data is immaterial for purposes of our analysis because we believe the work 

practice will lead to lower HAP emissions during periods of startup and shutdown and sources do not 

have to comply with numeric standards during periods of startup and shutdown, even if they have 

CEMS or sorbent traps collecting data during those periods.

Although the EPA is aware of the issues noted, particularly those related to operation below the acid 

dew point, we had no information at proposal that indicated that ESPs could, or would, not be 

operational at coal firing (we note the absence of claims that it is not possible to heat the ESP on clean 

fuels alone or that clean fuels could not be used for a longer period). In fact, our technical understanding

indicated that PM controls could be and were engaged prior to engagement of the FGD, either to prevent 

contamination of the wet FGD scrubber sludge or as part of a dry FGD process. We note that in some 

states, EGUs are required to place their PM APCDs in service, or have them operating, before solid fuel

or residual oil may be fired. For example, the draft “Air Pollution Control Operating Permit;

Operating Permit Renewal” for the Carney’s Point Generating Station includes the following 

requirement from the State of New Jersey:

12

...No coal or #6 fuel oil may be fired until all air pollution control apparatus is in 

operation... (see p. 55 of 133)

Similarly, the “Significant Revision of Part-70 Source Operation Permit” for the Weston Plant includes 

the following requirements from the State of Wisconsin:

13

 

12 See draft “Air Pollution Control Operating Permit Operating Permit Renewal” made available for 

public review on October 10, 2014, in docket ID EPA-HQ-OAR-2009-0234.

13 See “Significant Revision of Part-70 Source Operation Permit” dated September 23, 2014, in docket 

ID EPA-HQ-OAR-2009-0234.
142

...(2) (a) The permittee shall operate an electrostatic precipitator whenever solid fuel is 

fired in boiler B01 in a manner that controls particulate matter emissions from boiler B01 

so that the emission limitations in condition I.A.1.a.(1) are met.

(b) The permittee shall operate an electrostatic precipitator whenever solid fuel is fired in 

boiler B02 in a manner that controls particulate matter emissions from boiler B02 so that 

the emission limitations in condition I.A.1.a.(1) are met... (see p. 1)

...(i) Place ESP in service...(iv) Introduce coal to the combustion chamber while 

continuing to operate the startup fuel as the coal begins to ignite... (see p. 5)

Comments received on the proposed rule further reinforce the position that the PM APCDs can be 

operated from the beginning of solid fuel or residual oil firing, although a “grace” period of 1 hour may 

be indicated.14 Commenter 20275 states that “...it should take no more than one hour to phase in ESPs 

once pulverization commences.” Commenter 20303 suggests that “the time frame between coal 

combustion and all air pollution devices in operation be ‘as soon as practicable’ allowing a grace period 

of one hour.” Commenter 20269 states that “ESPs are started when the switch to coal is made.”

Commenter 20427 provides operational experience from a number of EGUs indicating that the safety 

concerns noted by industry commenters “are, at best, theoretical.” As noted above, commenter cites a

facility where “the four units...routinely operate ESPs during startup and shutdown events” and cites to 

the plant’s “Startup and Shutdown Minimization Plan.” Commenter indicates that the operator of the 

facility “notes that these procedures may be safely followed even in the face of contrary manufacturer’s 

recommendations.”

15 Commenter also cites to EPA-HQ-OAR-2009-0234-20240 and the included 

figures 1(a) and 2(a) indicating that the ESPs are energized prior to the initiation of coal firing.

The EPA notes that there are means of operation of ESPs to mitigate adverse conditions during startup. 

Certain commenters cited to problems encountered when firing “fuel oil” during startup. However, 

problems should not be encountered if natural gas or number 2 fuel oil (e.g., distillate) are used.16

Further, rapping intensity can be increased by 50 percent to limit adhesion of damp ash on electrodes.17

Hoppers and insulators should be heated prior to commencing startup.

18,19 Further, igniters can be 

 

14 The EPA notes that the presence of a different time-frame in a consent decree as noted by some 

commenters does not indicate that quicker action is not possible, merely that the listed time was agreed 

upon by the parties involved in arriving at the terms of the consent decree.

15

“...commitment to fully energize the precipitator prior to bringing the unit up to operating 

temperature, which is done by first combusting fuel oil followed by gradual introduction of coal, does 

not follow the Original Equipment Manufacturer (OEM) recommendation. That OEM recommendation 

calls for energizing the precipitator after the unit is at full operating temperature and combustion of fuel 

oil has ceased.”

16 Neundorfer. Lesson 6. ESP Operation and Maintenance. p. 6-5.

17 Ibid. p. 6-6.

18 U.S. EPA. Operation and Maintenance Manual for Electrostatic Precipitators. EPA/625/1-85-017. 

September 1985. p. 5-3.

19 Southern Environmental, Inc. Air Pollution Control Systems: Parts and Service Guide.
143

redesigned or replaced to accommodate additional clean fuel so as to maximize clean fuel use during 

startup.20

The EPA believes that one commenter is incorrect in stating that by “advocating co-firing of clean fuels 

after startup ends as an appropriate means to achieve compliance, the EPA is recognizing the limitations 

of certain pollution controls” and maintains that the best performing sources cannot achieve the limit at 

the end of startup with a 30-day rolling average. However, we recognize that other sources may want an 

additional compliance margin because of concerns about their ability to comply because it may be a 

more cost effective approach than modifying the facility to comply with the work practice in some other 

manner. We continue to believe that sources will be able to engage and operate their controls to comply 

with the standards at the end of startup, and that sources can make physical and or operational changes 

at the facility to ensure compliance at the end of startup.

As noted elsewhere in this document, the EPA believes it appropriate to base its startup/shutdown work 

practices on those practices employed by the better performers. As the above information indicates that 

ESPs can be energized within 1 hour of coal firing being started, we are finalizing that ESPs must be 

engaged within 1 hour of starting to fire coal, residual oil, or solid oil-derived fuel. We believe any 

reduced efficiency of the PM control when first engaged will be offset by the continued use of clean fuel 

and that the efficiency of these ESPs increases quickly with increased temps.

As noted elsewhere in this document, we recognize that there may be very limited circumstances that 

compel some alternative approach for a specific EGU. Sources that can demonstrate that their EGU has 

a documented manufacturer-identified safety issue that cannot be resolved should seek an alternative 

compliance method consistent with 40 CFR 63.6(g). In its request for the case-by-case determination, 

the EGU must provide documentation that demonstrates that it is not technically feasible to bring the 

PM control device on line safely using clean fuels alone, and explains what other measure the source 

will take to ensure comparable HAP emissions to those required under the final work practice.

Comment 132: Commenter 20411 states that there is continuing concern regarding how the MATS 

startup requirements will apply to EGUs that operate a baghouse. Commenter states that previous 

reconsiderations have left in place the work practice requirement that baghouses and some other APCDs 

must be in use as soon as any coal is burned in the boiler. Commenter states that however, this 

requirement is neither realistic nor consistent with equipment manufacturers’ specified operating 

procedures. Commenter states that this is especially the case for many older or smaller coal-fueled 

boilers that are not able to achieve the correct temperature for the operation of a baghouse while using 

the igniter to burn a “clean fuel” (e.g., natural gas), as is required under the MATS startup work practice 

standards.

Commenter 20411 appreciates the EPA’s reconsideration of the startup definition that would give coalfired EGUs with baghouses more flexibility in operating the baghouses during startup periods. 

Commenter states that although the EPA is asking for comments on changing the definition of startup as 

 

20 The EPA notes that commenters have also cited to the EPA ESP manual but would note that although 

some practices have not changed in the intervening 30 years (e.g., heating of insulators and hoppers), 

other practices have changed (e.g., time of energization) as indicated by the references to ESPs that can 

be, and are being, engaged at first firing of coal, residual oil, or solid oil-derived fuel.
144

“occurring at 25 percent of nameplate capacity plus 3 hours or the start of electricity generation plus 6 

hours, whichever comes first,” commenter believes that defining startup as only occurring at 25 percent 

of nameplate capacity plus 3 hours would provide coal-fired EGUs with baghouses sufficient 

operational flexibility to be able to operate the baghouses during startup safely and in a manner 

consistent with manufacturers’ specified operating procedures. Commenter recommends that during 

startup if the boiler and/or turbine generator “trips” and is no longer generating electricity that the 

startup process and time periods begin anew when the EGU begins generating electricity again.

Commenters 20389 and 20390state that fabric filter life is shortened by acid deposition due to below 

dew point temperature. Commenters 20389, 20390, and 20410 note that fabric filters can be 

permanently blinded by low temperature carbon combustion residuals, requiring filter replacement after 

every startup.

For FF used for PM control, Commenter 20390 states there are no minimum flow or temperature 

requirements prior to operation. Commenter states bags require pre-coating of material to protect them 

from corrosive attack during startup, either with sorbent from an upstream DSI or CDS system or per 

supplier’s recommendations. Commenter also notes that specific manufacturers may limit the number of 

compartments in service at reduced temperature. Commenter states bags have a maximum continuous 

temperature limit of approximately 375 °F depending on the bag medium. Commenter states a bypass 

can be included for high temperature excursions.

For SDA and FF in combination, Commenter 20390 states the potential for acid condensation in the FF 

can be greatly reduced with the startup procedure requiring the SDA be in operation at the same time as 

the FF. Commenter states if the temperature is too low entering the SDA, lime slurry may not dry in the 

SDA and will coat the walls of the SDA and carryover moist reagent and ash to blind the filter bags. 

Commenter reiterated the importance of multiple APCDs being treated as an integrated system with not 

only the boiler flue gas characteristics in mind but also the effect on APCD upstream of each APCD 

system.

Commenter 20390 indicates that most SDA and CDS systems have fabric filters as the PM control and 

that particulate removal can be maintained during startup and shutdown operating periods.

Commenter 20427 states that baghouses experience no difficulties during startup, are designed to be 

operated at all time, and cites an EPRI survey in 2010 that concluded baghouses are almost universally 

not bypassed during startup and experience no significant difficulties as a result of consistent use during 

startup. Commenter states the concerns raised by industry (condensation and acid corrosion) are 

applicable, if at all, to only a limited number of plants using older, suboptimal APCDs and do not justify 

further weakening of the rule. Commenter states that PM APCDs, igniters, and supply lines can be 

upgraded for those rare plants with concerns.

Commenter 20422 states that there is no justification for not operating baghouses during SS. Commenter 

cites to a 2010 EPRI “Power Plant Baghouse Survey” in which EPRI itself notes the vast majority of 

baghouses at a wide range of EGUs in its survey do not need to be bypassed during startup. In addition, 

commenter states the CAMD indicates 166 EGUs, over 12 percent of all coal-fired EGUs, have already 

installed baghouses or FF; as these are more effective in controlling PM immediately after startup and 
145

during normal operations, the EPA has little reason to weaken emission limits to accommodate outdated 

and ineffective ESPs.

Commenter 20433 provides a rebuttal that the 2010 EPRI survey cited involved baghouses at only about 

19 EGUs, all of which employed a specific type of baghouse known as a pulse-jet fabric filter (PJFF) 

baghouse. Commenter 20433 maintains that Commenter 20422 has provided no reason to extrapolate 

from that study the broad assertion that EGU owners/operators have “no justification for failing to 

operate baghouses.” Commenter 20433 indicates that from practical experience, EGU owners and 

operators know that operation during startup can damage baghouses, whose fabric filters are made of 

woven or felted fabric. Commenter states that, for example, baghouse operation during startup on oil is 

detrimental to its operation. It is impossible to ignite and maintain a stable flame on fuel oil without 

initially producing unburned carbon. These sticky particles can imbed in, and thereby damage, the fabric 

filters. If these particles imbed, gas pressure drop will increase, the bag’s life will be reduced, and there 

will be poor PM capture. The degraded performance will persist until replacement.

Commenter 20419 states that startups of baghouses are temperature-dependent, making startup times 

different at every EGU. For example, one of commenter’s members owns a coal-fired EGU that operates 

a baghouse for particulate control during periods of normal operation. Commenter notes that the flue gas 

must reach a certain minimum temperature before the baghouse is put into service to prevent acid 

corrosion from damaging the baghouse and causing it to fail and that baghouses also may fail if there is 

moisture carryover from the scrubber (moisture carryover, which can occur when the scrubber is put into 

service too early, results in bag blinding where the flue gas clogs the fabric pores). Commenter 

maintains that the bags then must be replaced because delta pressure (DP) increases with blinded bags, 

which can lead to bag failures and increased emissions; high DP also may require operating the EGU at 

reduced loads to decrease pressure.

Commenter 20421 states that the combustion of distillate oil in the EGU (for startup) would require, per 

the manufacturer’s recommendation, pre-coating of baghouse bags to minimize the possibility of 

irreversibly blinding (or plugging) the filter bags by volatile organic compounds, which are byproducts 

of distillate combustion. Commenter alleges that preliminary analysis shows that bag pre-coating may 

impact the EGU’s ability to meet the dispatch response times that are specified in their Power Purchase 

Agreements.

Response to Comment 132: Similar to ESPs, the EPA’s February 2012 final rule and the November 

2012 proposed rule included language that required fabric filters to be engaged once coal, residual oil, or 

solid oil-derived fuel firing was initiated. Commenters raised a number of concerns related to 

operational and safety issues related to the engagement of fabric filters this early in the process.

The EPA is aware of the issues noted, particularly those related to operation below the acid dew point. 

Comments received on the proposed rule further indicate that fabric filters, like ESPs, may be operated 

through startup after coal combustion as long as minimum temperatures are reached. We believe that 

sources can use clean fuels to bring the flue gas to appropriate temperatures and the information in the 
146

record supports that determination.21 Furthermore, the information and data submitted by the 

commenters does not support claims to the contrary or otherwise cause us to question our conclusions.

As noted in its comments above, Commenter 20390 indicates that there are means available for 

ameliorating the impacts of operation of a fabric filter below the acid dew point (e.g., pre-coating of the 

bags; required operation of the SDA, DSI, or CDS system during startup) and that particulate control can 

be maintained during startup. The EPA agrees that these practices, along with maximization of clean 

fuel use, can be used to minimize impacts on the fabric filter and reduce HAP emissions during startup.

Further, Commenters 20422 and 20427 note that industry information (available through EPRI) 

indicates that fabric filters may be operated during periods of startup. Further, information available 

from industry indicates that the recent trend is toward no use of bypass on startup with fabric filters.22

Therefore, as noted elsewhere in this document, the EPA believes it appropriate to base its SS work 

practices on those practices employed by the better performing EGUs. As the above information 

indicates that fabric filters can be operated during periods of startup, we are finalizing that fabric filters 

must be engaged within 1 hour of starting to fire coal, residual oil, or solid oil-derived fuel. The 1-hour 

period is designed to ensure that all sources can safely engage the PM controls, though many sources 

may need to increase their clean fuel capacity or modify their startup burners or take other action to 

comply.

The EPA agrees with one commenter that if the boiler and/or turbine generator “trips” during a startup 

period and is no longer generating electricity that the startup process and time periods begin anew when 

the EGU begins generating electricity again. However, if electricity generation began before the “trip,” 

the shutdown work practices would be applicable. The work practice requirement of engaging and 

operating the PM APCDs within 1 hour of coal, residual oil, or solid oil-derived fuel firing remains in 

effect regardless of whether electricity is generated.

3.6 Selective catalytic reduction - SCR

Comment 133: Commenter 20401 notes that the EPA’s definition of startup does not take into account 

operating requirements, such as specific minimum temperature conditions that are typically not met until 

well after electric generation has already begun, the omission of which presents a risk that a utility 

would be forced to run an SCR below the minimum operating temperature to avoid violating emissions 

limitations, reducing the efficiency of the SCR and causing substantial damage to the SCR and other 

associated equipment. Commenter notes that its specifications show that the minimum operating 

temperature for its planned SCR will be at least 600 °F.

 

21 For example, Commenter 20390 states that “[a]t some plants the startup fuel is co-fired and continues 

till 1/2 load and at other facilities it continues till 2/3 load. The capacity of each plant is different as to its 

ability to burn an auxiliary or startup fuel. Some plants only have igniters and can burn startup fuel only 

to about 10% of the design heat input while other plants have fuel burners that can burn auxiliary fuel up 

to full load.” Further, Commenter 20420 noted that its manufacturer’s startup procedures specified that 

the baghouses were to be “in operation throughout startup process” (see EPA-HQ-OAR-2009-0234-

20420, Attachment 3).

22 Widico, Mike. KC Cottrell, Inc. ICAC Technology Training Workshop: Fabric Filters, July 17, 2014.
147

Commenters 20390 and 20408 state that most recent SCR retrofits (i.e., since 2000) have no bypass for 

startup or shutdown (some ozone season SCRs do have bypass) and the flue gas must flow through the 

entire air pollution control train at all times – these inline systems bring certain startup operating issues 

with them along with certain environmental benefits). Commenters state SCR cannot function until a 

minimum flue gas temperature is reached – in general ammonia can only be injected when flue gas is 

greater than 600°F, and is affected by sulfur content, flue gas moisture, and ammonia content. 

Commenter 20408 notes that the conditions for a fully functioning SCR system will occur well beyond 

the time that electricity or useful thermal energy is initially achieved. Commenter 20390 indicates 

ammonium bisulfate is formed at lower temperatures and that shutdown must follow the same critical 

temperature shutoff of ammonia.

Commenter 20390 provides several graphs showing temperature profiles for warm and cold startups. 

Commenter states that one graph shows a warm startup where the SCR can be brought into service 

approximately 15 hours after initial firing of startup fuel and approximately 3 hours after the plant 

achieved 25 percent of nameplate capacity, and another graph shows the same warm startup, the SCR 

could be brought into service approximately 3 hours after the EGU was on coal, exceeding 6 hours after 

the start of electricity generation. Commenter indicates this example shows that even for warm startups, 

it is marginal that the SCR can be placed into service.

Commenter 20390 states one graph shows a cold startup following a long outage where critical 

temperature is not reached in the SCR for 60 to 90 hours after initial startup on auxiliary fuel, and this 

occurs at 60 percent load, long after the plant changed to coal firing and connected to the grid. 

Commenter states the SCR could be brought into service approximately 93 hours after initial oil firing 

and approximately 13 hours after achieving 25 percent of nameplate capacity. 

Commenter 20390 states that an economizer bypass can be added to most coal-fired plants using SCR 

and can reduce the time to reach critical temperature. Commenter indicates hot water bypass and a “flue 

gas slipstream bypass” may be used by most (but not all) boilers, although these technologies decrease 

boiler efficiency and add capital costs. In addition, Commenter states alternative boiler combustion 

modifications can minimize NOx emissions during startup and shutdown, such as overfire air (OFA) 

and/or low NOx burners, which also requires increased capital costs and the impact on boiler efficiency 

is dependent on system design and fuel burned.

Commenter 20425 states that the time frame to bring an SCR in service can vary based on the 

manufacturer, design and configuration. Commenter notes that, as directed by the manufactures 

instructions and specification, many SCR systems are not placed into service until substantial startup oil 

fire has ceased and proper temperatures at the SCR inlet have been achieved. Commenter maintains that 

this is per the manufacture’s direction to avoid blinding/fouling of the catalyst and also to avoid the 

potential of a fire within the catalyst. Commenter states that the time it takes to bring the SCR in service 

with proper ammonia flow can be 10 - 12 hours after the EGU is online or 8 - 10 hours after 25 percent 

of nameplate capacity is reached.

Response to Comment 133: See responses to both the legal and technical issues raised in these 

comments elsewhere in this RTC and the preamble to the final rule. The EPA also notes that in addition 

to the practice noted by commenter as a means to reduce the warm-up time, clean fuel use can be 

increased. The goal of our analysis was to identify the approximate time it took, on average, to initiate 
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operation of APCDs to determine an appropriate end to startup for purposes of defining the end of the 

work practice standard. The goal was not to seek the time it took for APCDs at all EGUs to become 

fully operational. The EPA does not believe that full functionality of an SCR is required for the purposes 

of startup under the MATS rule or that the longest times should govern. As noted in the Revised TSD, 

the EPA used an emission decline threshold of 20 percent and found that the average of the best 

performing 12 percent of EGUs initiate NOX control within 4 hours after the start of electricity 

generation. APCDs do not need to be fully functional at the end of startup. If an EGU is concerned about 

the efficiency of its controls at that time, it may combust clean fuels alone for a longer period to warm 

the system prior to generating electricity and/or continue to maximize the use of clean fuels after the end 

of startup to minimize emissions while the controls reach full capacity. 

3.7 Selective noncatalytic reduction - SNCR

Comment 134: Commenter 20390 states ammonia is injected for SNCR at flue gas temperatures of 

1600 to 1800 °F, and injection at lower temperatures can result in ammonia slip, and injection at higher 

temperatures produces less efficient NOx reduction. Commenter states typically boiler load is used as 

the control parameter because it is correlated with the proper temperature range, and SNCR is designed 

for a specific minimum boiler load operating condition. Commenter states SNCR control is often 

interlocked so that the SNCR will not be allowed to operate until it reaches the defined minimum boiler 

load (i.e., minimum temperature). Commenter states that high CO levels in the flue gas in the SNCR 

temperature range can have a significant effect on SNCR performance and also can affect the effective 

temperature range and that operating outside the defined temperature range may lead to ammonia slip, 

which can be detrimental to downstream components such as the air preheater, and PM and FGD

APCDs. Commenter states that on shutdown, SNCR are prevented from operating below the low boiler 

load/minimum operating temperature setpoint. Commenter states that 25 percent of nameplate capacity 

may not provide sufficient temperature for SNCR operation, 25 percent is not a typical low boiler load 

where SNCR is effective in reducing NOx, and notes that often 30 to 40 percent is typical for SNCR 

operation but is unit-specific and based on furnace temperatures. Commenter states furnace temperature 

is the key parameter and boiler load is only applicable in terms of how it relates to furnace temperature.

Response to Comment 134: See responses to both the legal and technical issues raised in these 

comments elsewhere in this RTC and the preamble to the final rule. There are no requirements for 

engagement of SNCR controls. Operators do not have to engage any controls within a specified time 

period (other than PM controls which must be engaged within 1 hour of firing of coal, residual oil, or 

solid oil-derived fuel); rather, they are only responsible for meeting the emission limits no later than 4 

hours after electricity generation using any approach the source deems appropriate. The use of clean 

fuels to the maximum extent possible will assist in heating the system to allow the APCD equipment to 

get to operating temperatures. Further, the EPA is unaware that SNCR has any effect on HAP emissions. 

Therefore, operators should be able to operate SNCR controls in the manner that best meets the EGU’s 

NOx emission requirements.

3.8 Activated sorbent injection (ACI)/Hg control

Comment 135: Commenter 20427 states the Hg limit can be met without further expansion of the 

startup exception. Commenter states that ACI provides effective control at low temperatures and loads, 

and in fact, is enhanced at lower temperatures. Commenter states industry has not provided any support 
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for the proposition that ACI is ineffective at lower temperatures, and the EPA has previously concluded 

that ACI is consistent across a variety of operating conditions (cites EPA-HQ-OAR-2009-0234-20223). 

Commenter notes that industry concerns for startup constraints on some SCR APCDs (must bypass to 

avoid catalyst contamination and gradually heat over 12 hours) and duct fallout can be addressed by 

adding ACI to avoid catalyst contamination and by controlling sorbent size (i.e., finer-sized), injection 

rate, and location, respectively. Commenter further notes the startup constraints for some SCR is only a 

concern for EGUs relying on co-benefit of NOx to avoid the reasonable expenses associated with ACI.

Commenter 20433 rebuts by saying nowhere in the docket entry cited by Commenter 20427 does the 

EPA discuss ACI, much less assert that ACI is “remarkably consistent” in its operation under differing 

conditions. Moreover, there are practical limitations to using ACI at low loads because the sorbent 

simply cannot be entrained in the exhaust gas stream without adequate flue gas velocity. Further, 

Commenter 20433 notes that, as explained in EPA-HQ-OAR-2009-0234-20180, sorbent injection, 

whether ACI or DSI, can only begin when a sufficiently high gas flow rate is achieved in the duct, 

which typically occurs at about 40 percent load. Commenter 20433 alleges that if injected too soon, the 

sorbent will not be properly entrained in the gas stream and instead will settle to the bottom of the duct, 

where with enough accumulation of material over a long enough period of time, the accumulated 

additional weight could cause structural damage and lead to duct collapse. Commenter 20433 notes that 

the sorbents that may be used for acid gas removal, such as Trona, may present worse settling problems 

(e.g., result in accumulation on the ESP’s inlet perforated plates) than activated carbon because of their 

higher density. More importantly, Commenter 20433 states that premature use of ACI also could cause 

fire, including in the air heaters and ESP hoppers.

Commenter 20424 believes that the standards should also be revised to allow the recognition of the 

constraints of application of ACI, which should be revised to allow the start of ACI after appropriate 

temperature is reached. 

Commenter 20390 states activated carbon generally performs better at lower temperature. Commenter 

notes there is a risk of fire if carbon stands for long periods in a hot environment because oxidation 

reactions occur on the surface of activated carbon which generates small amounts of heat – if the carbon 

is very concentrated, and kept hot a long time (and carbon is a great insulator) enough heat can be built 

up to lead to smoldering occurring. Commenter states activated carbon should not be injected in startup 

or shutdown conditions while oil-firing.

Comment 136: Commenter 20408 states that if ACI is injected into the flue gas before the EGU reaches 

stable load and the associated ESP is operating properly, there is a chance of fires starting in the ESP.

Commenter indicates that ACI should be started only after coal has been introduced to the boiler and is 

burning in a stable manner and that the conditions for a fully functioning ACI system will occur well 

beyond the time that electricity or useful thermal energy is initially achieved. Therefore, commenter

notes that ACI injection is not required under its permits until the EGU reaches stable load defined for 

the EGU. Because ACI will be one of the major control technologies used for Hg control, commenter

believes that the EPA needs to consider this when defining when startup ends.

Response to Comments 135 and 136: The final work practice standards do not specify when ACI 

injection must begin. The only specific requirement is that PM controls must be engaged within 1 hour 

of the introduction of coal or other primary fuel. Under the final requirements the operator would be 
150

responsible for measuring HAP emissions for compliance with the numerical limits within 4 hours after 

generation of electricity or production of thermal energy. At the end of startup (4 hours after generation),

the PM control device (e.g., an ESP or FF) would have been in operation for potentially up to 4 hours, 

and we believe that will be more than enough time for the PM controls to be fully or nearly fully 

operational before the introduction of activated carbon will be necessary for compliance with the 

numerical Hg limit. In any case, we believe that HAP emissions, including Hg emissions, will be as low 

if not lower during startup and shutdown due to the final work practice as they will be during all other 

periods.

3.9 Limestone injection

Summary of Comments Received Following November 30, 2012, Proposal

Comment 137: Commenter 20282 notes that in an FBC, if limestone is added too early in the startup 

sequence, the flame will be extinguished. Commenter states that FBUs that inject limestone must reach a 

minimum of approximately 1500 °F for the limestone to calcine, and thus become effective at reducing 

acid gases.

Commenter 20285 endorsed the EPA’s proposal to revise the startup and shutdown provisions 

applicable to EGUs that use FBC and that inject limestone for acid gas control, in recognition that such 

standards should reflect the unique operating conditions of FBCs and increase operational flexibility for 

FBC EGUs.

Commenter 20295 states that the EPA’s proposed work practice standards regarding limestone injection 

would prematurely start air pollution control systems, contrary to manufacturer specifications and 

risking safety concerns.

Commenter 20308 notes that where a thiosorbic lime scrubber is used, the chemistry of this system 

requires time to establish a seed crystal bed to support effective removal. Commenter states that until 

this seed crystal bed is established resulting in sufficient surface area, the reaction will not efficiently 

remove acid gases.

Response to Comment 137: The EPA understands that operational characteristics (including 

temperature) of APCDs used at power plants depend on manufacturer’s design and plant 

operating conditions and, therefore, are site-specific. Taking the comments into consideration, 

the final rule requires EGU source owners and operators to comply with the numeric MATS 

standards 4 hours after electricity generation. The rule requires sources to vent emissions to the 

main stack(s) when firing coal, solid oil-derived fuel, or residual oil in the EGU during startup or 

shutdown, and to engage and operate the PM control device(s) within 1 hour of firing those fuels.

Aside from the PM control device, sources are required to operate their control devices when 

necessary to comply with MATS or other applicable standards.

The EPA believes its final requirements for operation of the PM APCDs during periods of startup and 

shutdown are practical and will not cause any safety risks. The EPA also believes this requirement in 

conjunction with the final definitions of startup and shutdown and clean fuels requirement will ensure 

that EGU HAP emissions are minimized during startup and EGUs will be able to comply with the 
151

numerical standards applicable in periods other than startup and shutdown periods. However, as noted 

elsewhere in this document, we recognize that there may be very limited circumstances that compel 

some alternative approach for a specific EGU. Sources that can demonstrate that their EGU has a 

documented manufacturer-identified safety issue that cannot be resolved should seek an alternative 

compliance method consistent with 40 CFR 63.6(g). In its request for the case-by-case determination, 

the EGU must provide documentation that demonstrates that it is not technically feasible to bring the 

PM control device on line safely using clean fuels alone, and explains what other measure the source 

will take to ensure comparable HAP emissions to those required under the final work practice.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 138: Commenter 20397 states injection of lime cannot be safely initiated until the proper flue 

gas flow is achieved, which enhances mixing and contact of the dry sorbent with the flue gas and 

ensures lime does not drop out and lay in the flue gas ducts. Commenter states duct deposition initiates 

corrosion on duct surfaces, and duct support structure is not designed for large physical load that may 

result if the sorbent is added prior to reaching a gas velocity that suspends the material.

Response to Comment 138: See responses to both the legal and technical issues raised in these 

comments elsewhere in this RTC and the preamble to the final rule. The requirement to 

maximize the use of clean fuels will assist in heating the APCD equipment to operating 

temperatures while minimizing HAP emissions. The operator will be accountable for emissions 

for compliance purposes starting 4 hours after generation of electricity. There is no requirement 

that any APCD controls be engaged – other than the PM controls, which must be engaged within 

1 hour of firing coal, residual oil, or solid oil-derived fuel – only that the numerical emission 

limits be met not later than 4 hours after generation of electricity.

3.10 Shutdown

Summary of Comments Received Following November 30, 2012, Proposal

Comment 139: Commenter 20297 states that the use of the word “expeditiously” in Section 4 of Table 

3 in subpart UUUUU does not seem to convey the proper requirement for continuing operation of the 

control equipment though the end of a shutdown. Commenter suggests language similar to: “You must 

operate your limestone injection in FBC EGUs, dry scrubber, SNCR, and SCR systems as expeditiously 

as possible long as practicable...”

Response to Comment 139: The EPA thanks the commenter and has made appropriate edits to Section 

4 of Table 3 in subpart UUUUU.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 140: Commenter 20390 states that during normal shutdown, operators follow a set of 

procedures in which different APCDs are removed from service based on manufacturer 

recommendations, normally based on flue gas temperatures, and coal firing is reduced until auxiliary 

fuel can be brought into service. Commenter indicates that in an emergency shutdown or trip, ammonia 

to SCR or SNCR would be shut off immediately, water or slurry to a SDA, CDS, or NIDS would be 
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discontinued, but slurry or water would continue to a wet FGD to protect FRP/plastic components. 

Commenter states that during normal shutdown, an SCR may be taken out of service 2.5 hours prior to 

shutdown of the (boiler) EGU; however, how long the SCR may remain in service depends on system 

design. 

Commenter 20390 provides a summary table of typical shutdown procedures for multiple APCDs (see

Table 2). 

Table 2. Typical Shutdown Procedures (Commenter 20390).

APC Equipment Normal Shutdown Emergency shutdown

SCR Discontinue ammonia feed at 

minimum temperature 

Discontinue ammonia feed 

immediately, emissions no longer 

controlled 

SNCR Discontinue ammonia feed at 

minimum temperature 

Discontinue ammonia feed 

immediately, emissions no longer 

controlled

Wet FGD 

System can remain in service during 

shutdown. The number of recycle 

pumps in service should be limited to 

minimize blow back into inlet 

ductwork at reduced flow 

System can remain in service, 

number of recycle pumps in service 

should be limited to minimize blow 

back into inlet ductwork at reduced 

flow. Emergency quench available to 

cool flue gas in the event of a 

blackout situation. If emergency 

quench is required, emissions no 

longer controlled 

Spray dryer/baghouse 

Discontinue lime slurry feed at 

minimum temperature and flue gas 

flow 

Discontinue lime slurry feed 

immediately, emissions no longer 

controlled 

CDS/baghouse 

Discontinue water feed at minimum 

temperature and discontinue lime 

feed at minimum flue gas flow 

Discontinue water feed immediately 

followed by lime feed, emissions no 

longer controlled 

DSI or carbon 

injection system 

Discontinue sorbent feed at minimum 

flue gas flow 

Discontinue Trona and SBS feed at 

minimum temperature. Shut down 

carbon injection when firing oil. 

Discontinue sorbent injection 

immediately, emissions no longer 

controlled 

Baghouse 

System can remain in service during 

shutdown. May have to place 

compartments out of service based on 

flow and or temperature dependent 

manufacturers recommendations 

System goes into standby 

ESP 

System can remain in service during 

shutdown until flue gas temperature 

is reduced to 250 °F 

System goes into standby 
153

Comment 141: Commenter 20390 states that the low flue gas temperature problems cited for startups 

also occur during shutdown.

Response to Comments 140 and 141: The EPA believes that some of the conditions noted by 

commenter may be considered “malfunctions” and addressed under the final rule provisions applicable 

to malfunctions. We believe that the provisions of the final rule that require that emissions must be 

vented to the main stack(s) while firing coal, residual oil, or solid oil-derived fuel during shutdown, and 

require all applicable control devices to be operated as long as practicable throughout the shutdown 

period address commenter’s concerns and minimize HAP emissions. In addition to the fuel used prior to 

initiation of shutdown, if another fuel must be used to support the shutdown process, that additional fuel 

must be one or a combination of the clean fuels defined in 40 CFR 63.10042 and must be used to the 

maximum extent possible.

3.11 Other

Summary of Comments Received Following November 30, 2012, Proposal

Comment 142: Commenter 20271 states that it assumes that the work practice standards in Table 3 to 

subpart UUUUU of Part 63 for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGU during 

startup may not delay the startup of an APCD longer than would be needed to comply with a standard 

made applicable to the EGU by a permit limit or a rule other than subpart UUUUU. Commenter states

that if this assumption is correct, the EPA should clarify by specifically stating “a standard made 

applicable to the EGU by a permit limit or a rule other than this Subpart.”

Response to Comment 142: The EPA has revised Sections 3 and 4 of Table 3 in subpart UUUUU.

Comment 143: Commenter 20305 states that the proposal to allow plant operators to start “limestone 

injection in FGC EGUs, dry scrubbers, SNCRs, and SCRs as expeditiously as possible,” is sufficiently 

vague as to be unenforceable. Commenter recommends defining temperature thresholds as part of the 

work practice standard.

Response to Comment 143: Operational characteristics (including temperature) of APCD used 

at power plants depend on manufacturer’s design and plant operating conditions. Consequently, 

these characteristics are site-specific and, therefore, the EPA does not think it appropriate to 

prescribe broadly applicable temperature thresholds. 

The EPA maintains that the final requirements for operation of EGUs and attendant APCDs during 

periods of startup and shutdown are practical and will not cause any safety risks. The EPA also believes 

these requirements in conjunction with the final definitions of startup and shutdown periods are 

enforceable because of parameter and other operational data collected during these periods that will 

provide assurances that sources are complying with the work practice requirements.

Comment 144: Commenter 20302 agreed with work practice standards that require EGU source owners 

and operators to operate all control devices necessary to meet the operating standards that apply at all 

other times under the final rule (with the exception of limestone injection in FBC EGUs, dry scrubbers, 

SNCRs, and SCRs). Commenter agreed that that owners and operators of EGUs are responsible for 
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starting limestone injection in FBC EGUs, dry scrubbers, SNCRs, and SCRs as expeditiously as 

possible, but, in any case, when necessary to comply with other standards applicable to the source that 

require operation of those control devices.

Response to Comment 144: This comment requires no response.

4.0 WORK PRACTICE STANDARDS: TREATMENT OF IGCC

Summary of Comments Received Following November 30, 2012, Proposal

Comment 145: Commenters 20281 and 20400 observe that for IGCC EGUs, the EPA’s definition of 

startup and shutdown is based on the transition from firing clean fuels to syngas in the CT power block. 

Commenter notes that because the EPA’s definition of the affected IGCC source excludes the 

gasification system, the startup and shutdown definitions will reasonably accommodate IGCC operation. 

Commenter recommends that the EPA make no changes to either the definition of the affected source, or 

the startup and shutdown definitions for an IGCC.

Comment 146: Commenter 20243 supports the proposed revision of Table 3 to 40 CFR Part 63, subpart 

UUUUU, as it relates to the startup and shutdown provisions when using syngas. Commenter notes that 

the support is premised on the option of either flaring or routing to duct burners remains the option of 

the permittee and not the permit writer or regulator. Commenter states that it is important that flaring 

remain an option for routine startups and shutdowns and as a viable option for non-routine events such 

as EGU “trips” when the CT cannot combust syngas.

Response to Comments 145 and 146: After considering the comments on the need for flaring at IGCC 

EGUs, the EPA is providing both options, use of flaring or duct burners, for handling of syngas not 

combusted in the turbine during periods of startup and shutdown. The EPA believes that this will 

provide flexibility to owner/operators of IGCC EGUs to choose one or both of the options subject to 

operational constraints and economics at their IGCC EGUs.

Comment 147: Commenters 20281 and 20282 state that the work practice requirements proposed by the 

EPA are outside the scope of the MATS rule’s reach and therefore should be stricken. Commenters note 

that the definition of IGCC in the MATS rule does not include the gasification system. Commenters

state that the EPA cannot therefore impose work practice requirements on the gasifier, which is not 

subject to the rule in the first place.

Response to Comment 147: The EPA disagrees with the commenter that EPA is imposing a work 

practice on the IGCC gasifier, so we need not address whether EPA agrees with the conclusion that such 

units could not be regulated under this rule. Instead, the work practice standard requires the use of clean 

fuels during startup. If the IGCC operator wants to use its syngas as a startup fuel, it must ensure that 

such gas is compliant with the clean fuels definition or startup on a clean fuel as defined in the final rule.

Comment 148: Commenter 20282 states that if the gasification system were subject to the startup and 

shutdown provisions, the regulatory language should retain both alternatives for meeting the work 

practice requirements: the owner/operator could either (1) flare syngas, or (2) route the syngas to the 
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duct burners, and then to the heat recovery system generator. Commenter notes that the flaring option is 

especially critical as the re-routing option can only be used by IGCC EGUs under limited circumstances.

Response to Comment 147: The EPA is finalizing both alternatives. See the response above.

Comment 148: Commenter 20281 states that the proposed new requirements for IGCC EGUs for 

handling syngas that is not fired in the CT are not necessary.

Response to Comment 148: From the comments, the EPA understands that generally IGCC designs 

incorporate provisions for flaring of syngas not fired in the turbine. Because syngas may contain HAP 

compounds, to minimize HAP emissions during periods of startup and shutdown, the EPA is codifying 

requirements for handling syngas not combusted in the turbine during these periods. 

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

4.1 Option 1 Flares

Summary of Comments Received Following November 30, 2012, Proposal

Comment 149: Commenter 20282 states that the ability to flare syngas is an engineering design aspect 

of the IGCC gasification system, and is a permitted form of emissions under current Title V permits. 

Commenter provides discussion about safety reasons for the use of flares.

Response to Comment 149: The EPA is finalizing this option.

Comment 150: Commenters 20281 and 20282 responded to the EPA’s request for comments on the 

need to flare unfired syngas and if unfired syngas could be routed into the system for all IGCC EGUs. 

Commenter states that the language could be read to suggest that syngas could be routed to the gasifier 

and combusted there. Commenter states that the syngas lacks sufficient pressure for re-injection and the 

gasifier is a once-through system, which does not support re-routing of the syngas.

Response to Comment 150: The EPA is now aware that there are technical reasons why it may not be 

possible to route unfired syngas back to the system (gasifier) at IGCC EGUs. These reasons include the 

fact that because the gasifier operates at high pressures, the oxygen, coal solution, and startup natural 

gas must be pressurized before they can be injected into the gasifier. Once the syngas leaves the gasifier 

and enters the clean-up system, it decreases in pressure and would have to be re-pressurized before it 

could be routed back into the gasifier. IGCC units have no provision for doing this. In addition, a 

gasifier is designed as a “once through” system. Gasifiers need to have a constant flow of material into 

and out of the system. Routing all the syngas back into the gasifier would be analogous to taking the tail 

pipe of an automobile and routing it back into the air intake. Before long the CO2 will accumulate to 

levels high enough so that the automobile’s engine would stall. In the case of an IGCC, the gasification 

process will be extinguished. See, e.g., EPA-HQ-OAR-2009-0234-20400. As such, the EPA is not

requiring routing of unfired syngas back to the gasifier in the final rule.

Comment 151: Commenter 20281 states that if the EPA were to impose any additional requirements for 

syngas, these requirements must allow sources to flare for a number of reasons with safety being the 
156

most important. Commenter provides discussion that the flaring step of an IGCC startup is relatively 

short and ordinarily last less than 2 hours, and only clean gas is flared, thus, emissions are low. 

Commenter states that it is technically infeasible to require syngas not used in the CT to only be used in 

duct burners.

Commenters 20281 and 20282 note that flaring is a required practice for safety reasons, and is permitted 

under facilities’ Title V operating permits. 

Commenter 20299 states that IGCC plants have and will continue to require flare stacks for the safe and 

orderly disposition of syngas such as during infrequent but potential process malfunctions, rapid 

disposition of unused sweet syngas that is necessary upon gas turbine trips, or for excess syngas trim 

during rapid load reductions.

Response to Comment 151: The EPA notes that it is providing both options, use of flaring or duct 

burners, for handling of syngas not combusted in turbine during periods of startup and shutdown. The 

EPA believes that this will provide flexibility to owner/operators of IGCC EGUs to choose one or both 

of the options subject to operational constraints and economics at their IGCC EGUs. Given the 

inherently low HAP content of properly cleaned syngas, we believe the alternative options are 

equivalent.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 152: Commenter 20400 believes that the EPA’s proposed IGCC syngas requirements fall 

outside of the source definition of an IGCC EGU. Commenter states that as it has defined an IGCC in 

the final MATS rule and in the response to comment documents, the EPA has excluded the gasification 

system from regulation under MATS. Commenter states that as a result the portion of the gasification 

system that flares the syngas is excluded from the definition of an affected IGCC EGU source. Flares 

can accept syngas from different parts of the gasification system. Commenter states that in the 

reconsideration rulemaking, the EPA did not propose any expansion of the definition for an IGCC EGU, 

nor has it proposed any in the current rule making. Commenter states that as a result the EPA has no 

legal basis in this rule making for imposing any requirements on the use of syngas.

Response to Comment 152: See the preamble to the final rule and responses to other comments above 

for responses to these comments.

Comment 153: Commenter 20400 states that any requirements for the treatment of IGCC syngas during 

startup and shutdown periods must include the ability to flare syngas. Commenter states that in the 

reconsideration proposal, the EPA stated that it understands that at an IGCC EGU, syngas is generated 

in the gasifier and combusted in the turbine. Commenter states that the EPA recognizes that during the 

startup and shutdown periods, some or all of the syngas produced by the gasifier may not be combusted 

in the turbine. Commenter states that the EPA solicited comments on the need to flare the unfired 

syngas, if it is more appropriate to require routing of the unfired syngas back into the system for all 

IGCC EGUs, and on the costs of adding duct burners, should they be required. Commenter states that in 

this action, the EPA stated that that various commenters support flaring as an option. Commenter is one 

of the few utilities that have actual operating experience with IGCC EGUs. Commenter states that it 

constructed the IGCC EGUs at the Wabash River Repowering Project which began commercial 
157

operation in 1995, and the Edwardsport Station which began commercial operation in June 2013.

Commenter states that if the EPA does impose additional requirements for syngas during startup and 

shutdown periods, those requirements must allow sources to flare for a number of reasons with safety of 

equipment and personnel being the most important.

Commenter 20428 states that the definition must allow gasifiers to IGCC EGUs to have the option of 

flaring syngas or rerouting to duct burners.

Comment 154: Commenter 20400 states that the EPA’s proposed requirements are unwarranted 

because flaring is already a required practice for safety reasons. As commenter’s experience has shown, 

it is a frequent and foreseeable occurrence in an IGCC EGU, the CT will trip, halting the flow of air to 

the duct burners and all combustion of syngas in the turbine and the duct burners. Commenter states that 

the gasifier and other components can also cause an EGU shutdown. Commenter states that when this 

occurs, the syngas will become bottled up and accumulate in the system causing pressure to increase. 

Commenter states that to protect the equipment and prevent uncontrolled releases of syngas, pressure 

safety valves are installed in different parts of the system. Commenter states that the valves open to 

relieve pressure and the discharge is routed to the flare system. Commenter states that engineering codes 

require the use of pressure relief systems which is why the equipment vendors include these components 

in the facility design.

Commenter 20400 states that because syngas contains CO and hydrogen, a release of syngas that is not 

flared will create a fire and explosion hazard, as well as an inhalation hazard. Commenter states that 

flaring converts the CO and hydrogen to carbon dioxide (CO2) and water vapor. Commenter states that 

the operation of these flares is permitted under the stations’ Title V operating permits. Commenter states 

that normally flaring is limited to purified syngas during startup or shutdown events. Commenter states 

that however during upset conditions small amounts of raw syngas could also be flared.

Commenter 20400 states that in the proposal, the EPA solicited comments on “the need to flare the 

unfired syngas, if it is more appropriate to require routing of the unfired syngas back into the system for 

all IGCC EGUs...” Commenter is concerned that the EPA could be operating under the belief that the 

syngas could also be routed back into the gasifier and combusted, which is not possible for two reasons. 

Commenter states that first, because the gasifier operates at high pressures, the O2, coal solution and 

startup natural gas must be pressurized before they can be injected into the gasifier. Commenter states 

that once the syngas leaves the gasifier and enters the cleanup system, it decreases in pressure and would 

have to be re-pressurized before it could be routed back into the gasifier. Commenter states that IGCC 

EGUs have no provision for doing this. Commenter states that second, a gasifier is designed as a “once 

through” system. Commenter states that gasifiers need to have a constant flow of material into and out 

of the system. Commenter states that routing all the syngas back into the gasifier would be analogous to 

taking the tail pipe of an automobile and routing it back into the air intake. Commenter states that before 

long the CO2 will accumulate to levels high enough so that the automobile’s engine would stall. 

Commenter states that in the case of an IGCC, the gasification process will be extinguished.

Response to Comments 153 and 154: The EPA notes that it is providing both options, use of flaring or 

duct burners, for handling of syngas not combusted in the turbine during periods of startup and 

shutdown. The EPA believes that this will provide flexibility to owner/operators of IGCC EGUs to 

choose one or both of the options subject to operational constraints at their IGCC EGUs.
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Comment 155: Commenter 20400 states that during a routine startup the flaring of treated IGCC syngas 

occurs for only a short period of time. Using commenter’s Edwardsport IGCC as a model, syngas is 

produced in the gasifier and then goes through a clean-up system to remove pollutants including HAP 

prior to it being fired in the CT. Commenter states that during a startup, the CT is fired first using natural 

gas to produce electricity and to generate steam that is used for startup of the gasification system. 

Commenter states that later, the gasifier is fired with natural gas to warm the equipment and establish 

flow through the gas cleanup system. Commenter states that once the gasifier reaches the proper 

conditions, a coal slurry solution is introduced to begin the gasification process. Commenter states that 

the raw syngas then flows into the gas cleanup system before being flared. Commenter states that the CT

fuel cannot be converted from natural gas to syngas until the gasifier reaches stable operating conditions 

which occur at about 50 - 60 percent of the gasifier capacity. Commenter states that once the gasifier 

reaches those conditions, the clean syngas valve is phased into the turbine while the natural gas is 

phased out. Commenter states that this fuel transition phase normally takes less than a half hour. 

Commenter states that once all syngas is channeled into the turbine, flaring of syngas ceases.

Commenter 20400 states that there are two important facts that show that gasifier emissions are 

minimized during startup flaring. Commenter states that the first is that the actual flaring step of a 

startup is relatively short and ordinarily last less than 2 hours. Commenter states that the second is that 

only clean syngas is flared during a routine startup. Commenter states that the gasification process 

converts much of the HAP into a solid material in the gasifier. Commenter states that the gas cleanup 

system, which at Edwardsport includes an activated carbon bed, then removes sulfur compounds, acid 

gases, Hg, other remaining HAP, and other materials. Commenter states that with the gas cleanup 

system in full operation, the HAP emissions from flaring syngas are essentially the same as using syngas 

in the CT or duct burners. Commenter states that therefore the EPA need not be concerned about flaring 

syngas from an emissions perspective, even though the gasifier emissions are outside of the scope of the 

MATS regulation.

Response to Comment 155: This comment requires no response.

4.2 Option 2 Duct Burners

Summary of Comments Received Following November 30, 2012, Proposal

Comment 156: Commenters 20281 and 20282 state that it is not always feasible to combust gas in duct 

burners, because if the turbine is not operational, air from the CT does not feed into the heat recovery 

steam generator (HRSG) and combustion in the HRSG of any fuel, including syngas, cannot occur. 

Commenters provide discussion about these points.

Commenter 20245 states that the EPA has proposed two options for syngas not fired in the CT. 

Commenter states that for process safety reasons, IGCC EGUs are designed to, and must be allowed to 

flare syngas during startup and shutdown periods. Commenter states that during startups and shutdowns, 

the syngas produced by the gasifiers may not meet the specifications required for use in the CT and/or 

duct burners and its use could cause damage to the equipment and/or void the equipment manufacturers’

warranties. Commenter notes that of greater concern, is that during startups and shutdowns, the IGCC 

EGU’s power block may not be in operation and, therefore, not capable of accepting syngas. Commenter
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states that operating HRSG duct burners without the exhaust flow from an operating CT is a safety 

hazard. Based on the foregoing, Commenter requests that IGCC EGUs, including those equipped with 

duct burners in the HRSG, be allowed to flare syngas during startup and shutdown periods. According to 

commenter, regulatory requirement to operate the EGUs in a manner which may compromise safety and 

vendor guarantees would act as barriers to the implementation of this technology. 

Commenter 20299 states that duct burners should neither be recommended nor required as an alternative 

to flare stacks. Commenter provides discussion about how duct burners are not capable of handling 

upsets in the same manner or capacity as a flare. Commenter notes that the primary goal of design and 

proper operational procedures (work practices) is to minimize flaring which will continue to reduce the 

benefit of using duct burners for other than normal operation. Commenter concluded that the potentially 

beneficial but infrequent utilization of unfired syngas is far outweighed by the additional cost, 

impracticality and operational complexity of employing duct burners for startup and shutdown transients 

or malfunctions and that they neither be required by rule nor offered as an alternative to flaring.

Response to Comment 156: The EPA notes that it is providing both options, use of flaring or duct 

burners, for handling of syngas not combusted in turbine during periods of startup and shutdown. The 

EPA believes that this will provide flexibility to owner/operators of IGCC EGUs to choose one or both 

of the options subject to operational constraints at their IGCC EGUs.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

Comment 157: Commenter 20400 states that it is technically unfeasible to require syngas not used in 

the CT to be used only in duct burners. Commenter states that the EPA has proposed requiring sources 

to combust syngas in the HRSG duct burners when it is not used in the CT. Commenter states that this 

approach would only be feasible in some limited instances, but it cannot be mandated for all cases for 

two reasons. Commenter states that the first is that O2 will not always be available to the duct burners 

for combustion. Commenter states that the first section of a CT operates as a large air compressor. 

Commenter states that the motive force that drives the compressor is the combustion of either natural 

gas or syngas. Commenter states that the hot gases produced drive the turbine section of the CT which is 

directly coupled to the compressor. Commenter states that not all of the O2 in the inlet air is utilized for 

combustion in the CT. Commenter states that as the hot exhaust gas flows out of the CT, it enters the 

HRSG where the duct burners use a portion of the remaining O2 to combust additional fuel supplied to 

the duct burners. Commenter states that the EPA’s basic premise is that when syngas is not combusted 

in the CT, the syngas can be combusted by the duct burners. Commenter states that the first flaw is that 

there will be times when the CT shuts down and cannot operate when there is syngas in the system. 

Commenter states that when the CT shuts down, it stops providing the combustion air into the HRSG 

that is necessary for combustion. Commenter states that as a result combustion of any fuel, including 

syngas, is simply not possible.

Commenter 20400 states that the second reason that duct burners cannot be used to combust all syngas 

generated during a startup is because they are too small. Commenter states that duct burners are 

generally designed to have a heat input that is about 25 - 30 percent of the CT. Commenter states that 

thus, the amount of syngas generated during a startup will exceed the capacity of the duct burners. 

Commenter states that also, duct burners are not always operating. Commenter states that if an IGCC 

EGU trips suddenly, then there will not be enough time to start the duct burners before the syngas 
160

system pressure increases to the point that must be sent to a flare. Commenter states that, in summary, 

duct burners alone cannot be used as an alternative, so flaring must be allowed.

Response to Comment 157: The EPA notes that it is providing both options, use of flaring or duct 

burners, for handling of syngas not combusted in turbine during periods of startup and shutdown. The 

EPA believes that this will provide flexibility to owner/operators of IGCC EGUs to choose one or both 

of the options subject to operational constraints at their IGCC EGUs.

5.0 OTHER

Summary of Comments Received Following November 30, 2012, Proposal

Comment 158: Commenter 20280 asks the EPA to reinstate the use of the diluent cap and minimum 

electrical production rate specified in the proposed Rule at all times when the EGU is operating in low 

load conditions (including, but not limited to, startup and shutdown), and provide sources with the 

ability to comply with a unit-specific startup definition. Commenter states that low load conditions that 

occur during the startup process and at other times during EGU operation can result in calculated 

emissions rates that are unrealistically high. Commenter notes that equations for calculating compliance 

with input-based limits, however, are not designed to be used in these situations because they assume 

complete combustion and normal operating conditions. Commenter states that as a result, these 

equations overestimate emission rates when CO2 concentrations are very low or O2 concentrations are 

very high, including during startup.

Commenters 20272 and 20281 state that some CEMS measurements are not accurate during startup, or 

are otherwise not appropriate for use in compliance calculations. Commenter expresses particular 

concern about: (1) the use of diluent (O2 or CO2) values from CEMS in the equations for calculating 

compliance with input-based limits (e.g., limits expressed in lb/MMBtu or pounds per trillion British 

thermal units (lb/TBtu)); (2) the use of uncorrelated data from PM CEMS; and (3) the effect of low 

generation levels on output based emissions rates. Commenters discuss each of these issues. 

Commenters state that an expanded startup period would solve each of these problems.

Commenter 20306 recommends that work practice standards should identify periods when CEMS do not 

provide accurate indications of emissions during startup or shutdown. Commenter discusses when this 

occurs, and notes that these occurrences are marked in Commenter’s quarterly excess emission reports. 

Commenter notes that the accuracy of CEMS is not verified during startup and shutdown conditions 

because the EPA Reference Tests must be performed at steady state conditions that are not available 

during startup or shutdown.

Commenter 20306 states that CEMS data collected and reported during startup and shutdown conditions 

should be clearly marked and not used as part of 30-day or other rolling averages to determine 

compliance with the MATS rule. Commenter suggests that the management and reporting of CEMS data 

during startup and shutdown periods should be defined in the SS Plan that is submitted for approval to 

the state or local permitting agency.

Commenter 20272 states that equations for calculating compliance with input-based limits, overestimate 

emission rates when CO2 concentrations are very low or O2 concentrations are very high, including 
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during startup. Commenter states that to ensure that EGUs that opt to use CEMS are not penalized by 

this phenomenon, the EPA must either define startup and shutdown as ending (and beginning) after (and 

at) the point when diluent concentrations reflect normal operation, or provide for a diluent “cap” similar 

to the one provided in final Appendix A for Hg. (40 CFR Part 63, subpart UUUUU, appendix A, section 

6.2.1.2, 77 FR 9606)

Commenter 20272 states that PM CEMS’ ability to monitor PM is dependent on correlation of the PM 

CEMS output to a reference method stack test. Commenter states that because the EPA reference 

methods cannot reasonably be performed under startup and shutdown conditions, PM CEMS are not 

(and cannot reasonably be) correlated during these periods. Commenter states that the uncorrelated data 

from PM CEMS may be inaccurate for many reasons, including differences in stack flow (which can 

result in temporary stratification of pollutant concentrations in the stack) and particle characteristics 

(e.g., from combustion of different fuels) during startup and shutdown. Commenter states that neither

the February 16, 2012, final rule nor the proposed reconsideration rule account for these accuracy issues.

Commenter 20282 states that the very stringent limits in the MATS rule impose near zero emissions 

requirements that do not provide a practical opportunity for over control to make up for the higher 

emissions that can occur when the control equipment is not fully functioning during startup.

Commenter 20321 discussed the controls, the controls’ costs, and low emission rates for its EGUs. 

Commenter states that even with its advanced control systems, it will be difficult to meet the emission 

requirements during periods of startup and shutdown.

Response to Comment 158: In the February 2012 final MATS rule, the EPA established work practice 

standards rather than numeric emissions standards for periods of startup and shutdown. In the 

reconsidered final rule, the EPA is finalizing definitions and work practice standards for startup and 

shutdown periods, which it believes are broadly applicable. Pollutant emission rates measured during 

startup and shutdown hours are not used to determine compliance with the emission standards, but EPA 

wants the data to evaluate as part of the CAA section 112(d)(6) and (f) reviews.

In response to comments regarding use of the diluent cap, the reconsidered final rule allows the 

appropriate diluent cap value to be used to calculate heat input-based emission rates for all monitored 

pollutants (i.e., for Hg, SO2, HCl, PM, and/or hydrogen fluoride (HF)) during startup or shutdown 

periods, whenever the quality-assured hourly average CO2 concentration measured by the CEMS is 

below the cap value or when the quality-assured hourly average O2 concentration measured by the 

CEMS is above the cap value. This is consistent with section 3.3.4.1 of 40 CFR Part 75, Appendix F, 

which applies to the calculation of heat input-based NOx emission rates.

Comment 159: Commenter 20282 disagreed with the EPA’s statement in the preamble in the final 

MATS rule that “periods of startup, normal operations, and shutdown are all predictable and routine 

aspects of a source’s operations,” 77 FR 9382. Commenter suggests that if the natural gas market share 

increases and wind generation increases, it is possible that coal EGUs in deregulated states will have 

more frequent shutdowns and startups that are the result of state grid operator demands and not within 

the control of an individual utility.
162

Response to Comment 159: The EPA disagrees with the commenter’s assertion. Operation within a 

deregulated state includes a calculus of items to be considered; among them are the possibility of more 

frequent startups and shutdowns as a routine matter. In any case, we believe compliance with the work 

practice standards during startup and shutdown periods will lead to HAP emissions that are on average 

at or below the numerical standards because of the requirement to combust only clean fuels for the 

beginning periods and to maximize the use of clean fuels throughout the 4-hour period after electricity 

production begins and coal, residual oil, or solid oil-derived fuel is added to the EGU and the PM 

controls are brought on line.

Comment 160: Commenter 20308 recommends that an EGU should not have to sample for Hg with 

sorbent traps until startup has ended. Commenter states that if a site is using continuous monitoring, 

startup and shutdown data may be available. Commenter notes that because data from sorbent traps and 

other test results will be submitted to the EPA via the Emissions Reporting Tool (ERT), and continuous 

data will be submitted using the Emissions Collection and Monitoring Plan System (ECMPS), this 

appears to be a clear and easily discernible breakpoint.

Commenter 20308 notes that for shutdown periods, when monitoring for Hg with sorbent traps, the 

shutdown periods should be very short and measurements will not be able to be separated out but will 

use data from the last traps analyzed; and, have the potential of skewing any presented data.

Response to Comment 160: 40 CFR 63.10020 requires all monitoring systems to operate and collect 

data at all times, except for monitoring system malfunctions, out-of-control periods, or when certain 

quality assurance (QA) activities are performed. Therefore, all monitoring systems (including sorbent 

trap systems) must record and report data during startup and shutdown periods, provided that the 

systems are not out-of-control or undergoing required QA testing. 

The reconsidered rule allows EGU owners or operators who choose to use Hg sorbent traps for 

compliance purposes either to include Hg emissions during startup or shutdown periods with those from 

periods other than startup or shutdown or to use one Hg sorbent trap monitoring system for startup or 

shutdown periods and another Hg sorbent trap monitoring system for other periods. A separate Hg

sorbent trap monitoring system used only for periods of startup or shutdown would keep the startup and 

shutdown emissions separated from emissions during normal operation, so as not to include the startup 

and shutdown emissions in the 30- (or 90-) boiler operating day rolling average emission calculations. 

As mentioned earlier, Hg emissions during startup or shutdown periods are not expected to be 

problematic, given that the duration of those periods is supposed to be minimized, that clean fuels are to 

be burned during those periods, that control devices are to be operated as long as possible, and that the 

averaging period associated with the emissions limit is long (30- or 90- boiler operating days). This 

expectation is consistent with that of commenter 20428, who identifies “...the short duration of startup 

relative to the normal operating period for a sorbent trap, and the use of clean startup fuels...” as 

providing such low emissions data as to be below detection levels. 

Although the EPA disagrees with not collecting emissions data during periods of startup or shutdown, 

the EPA agrees with commenters that emissions should be low. This expected emissions behavior is 

shown in a figure submitted by one commenter;

23 assuming that the EGU operated at the hourly values 

 

23 See Figure 9 from Attachment I from Commenter 20428 
163

shown for startup or shutdown periods, that the EGU operated at normal load for all other periods, and 

that the EGU owner or operator chose to meet the 30-boiler operating day Hg emissions limit, then by 

having average hourly Hg emissions during periods other than startup or shutdown no larger than 1.14 

pounds Hg per TBtu (about 95 percent of the emissions limit), the EGU would demonstrate compliance. 

In another example, Hg emissions from a common stack are shown in a figure submitted by one 

commenter.24 Given the same assumptions as for the previous example, then by having average hourly 

Hg emissions during periods other than startup or shutdown no larger than 1.18 pounds Hg per TBtu 

(about 99 percent of the emissions limit), the EGU would demonstrate compliance. We note that these 

data were collected prior to application of the work practice to these units and the commenters do not 

assert that they were complying with the work practice at the time the testing was conducted or indicate 

that the EGUs at issue are among the best performers under any metric used in this final rule to 

determine the work practice requirements. For these reasons, we believe the HAP emissions will likely 

decrease significantly more when sources are complying with the final rule.

The EPA notes that Commenter 20308 is incorrect in stating that Hg sorbent trap data will be submitted 

through the ERT. While sorbent trap data are to be collected via the ERT when the module is ready, 

sorbent trap data are to be submitted using ECMPS.

Comment 161: Commenter 20305 states that the EPA did not provide a rationale for re-opening the 

startup and shutdown work practice standards.

Response to Comment 161: The EPA provided its rationale for granting reconsideration of the SS

provisions of MATS in the reconsideration proposal notice (77 FR 71330).

Comment 162: Commenter 20297 states that its EGUs cannot initially startup while routing emissions 

through the FGD to the main stack where the primary CEMS are located. Commenter cites Section 3, 

Table 3: “You must operate all CMS during startup.” Commenter states that it operates CEMS for 

Opacity and SO2 on emissions routed to the bypass stack for startup purposes, but does not believe it 

should be necessary to operate redundant Hg monitors in this location as well. Commenter states that the 

Hg emissions standard is a 30-day average and alternative data collection methods such as fuel sampling 

can be utilized to determine worst case Hg emissions during the times when startup occurs.

Response to Comment 162: First, the EPA notes that continuous opacity monitoring systems are 

COMS, not CEMS. Although the EPA agrees with the commenter that Hg emissions during periods of 

startup or shutdown are expected not to have much impact on the 30-boiler operating day rolling 

average, the commenter will need to monitor its EGUs’ Hg emissions during those periods, consistent 

with the final rule. The Hg monitors for the bypass stacks need not be redundant Hg CEMS (as the 

commenter appears to suggest); sorbent trap monitoring systems could be used.

Comment 163: Commenter 20282 states that comments that were in commenter’s MATS 

Reconsideration Petition that were not addressed in the proposed rule are: emission monitoring, 

compliance calculation, and reporting during startup and shutdown; how startup and shutdown 

definitions and work practice provisions apply to EGUs that share a common stack; and that the EPA’s 

definitions of startup and shutdown are insufficient to exempt all periods of non-normal operation, 

 

24 See Figure from Attachment V from Commenter 20428. 
164

which would penalize EGUs during periods of abnormally low CO2 values and abnormally high O2

values. 

Commenter 20282 discussed the difficulty of obtaining accurate measurements and under low load 

conditions, the difficulty of calculating output based emission values when there is low or no output, and 

how compliance calculations assume complete combustion and normal operating conditions.

Commenter 20281 states the proposed reconsideration rule also does not resolve how the startup and 

shutdown definitions and work practice provisions apply to EGUs that share a common stack.

Response to Comment 163: In the February 2012 final MATS rule the EPA established work place 

standards rather than numeric emissions standards for periods of startup and shutdown. In the 

reconsidered final rule, the EPA is finalizing definitions and work practice standards for startup and 

shutdown periods, which it believes are broadly applicable. The work practice is not an exemption.

As mentioned elsewhere, regarding use of the diluent cap, the reconsidered final rule allows the 

appropriate diluent cap value to be used to calculate heat input-based emission rates for all monitored 

pollutants during periods of startup or shutdown (i.e., for Hg, SO2, HCl, PM, and/or HF), whenever the 

quality-assured hourly average CO2 concentration measured by the CEMS is below the cap or when the 

quality-assured hourly average O2 concentration measured by the CEMS is above the cap for EGUs in 

startup and shutdown mode, whether for EGUs with single stacks or for EGUs that share a common 

stack. This is consistent with section 3.3.4.1 of 40 CFR Part 75, Appendix F, which applies to the 

calculation of heat input-based NOx emission rates. Moreover, the reconsidered final rule allows the use 

of a default electrical load of 5 percent when no electricity is being generated during periods of startup 

or shutdown (once electricity is generated during startup, sources are required to use actual electrical 

output instead of the 5 percent default value, even if the electricity level is below 5 percent). Application 

of a diluent cap and a default electrical load should alleviate commenters’ concerns over emissions 

calculations for compliance during periods of startup or shutdown when units share a common stack.

As mentioned earlier and in the reconsidered final rule preamble, EGUs with common stacks may either 

monitor each EGU venting to the stack separately, or monitor at the common stack (provided that the 

EGUs are subject to the same emission limits). If monitoring is done at the common stack, then the 

startup or shutdown provisions are applied whenever any EGU served by the stack is in the startup or 

shutdown mode, as defined in the final rule. All monitoring systems are required to operate during the 

startup and shutdown periods. Except when EGU owners or operators choose to include Hg emissions 

measured with sorbent trap monitoring systems during periods of startup or shutdown, data recorded 

during startup and shutdown are excluded from the compliance calculations.

Summary of Comments Received Following June 25, 2013, Reopening of Public Comment Period

5.1 Use of diluent cap

Comment 164: Commenters 20388 and 20405 suggest that the EPA adopt measures recommended by 

the utility industry on the issues discussed in the June 25, 2013, notice, and indicate industry’s 

recommendations are reasonable and follow good engineering practice. 
165

Commenters 20384, 20387, 20389, 20390, 20397, 20401, 20410, and 20428 support reinstatement of 

diluent caps for non-mercury HAP during periods of startup and shutdown. Commenter 20422 indicates

that use of the diluent caps should be caveated.

Commenters 20401 and 20411 support the use of diluent cap values during periods of startup in order to 

prevent emission reported during startup from being grossly overstated when complying with heat input 

based emission standards. Commenter 20411 believes that allowing the use of the 40 CFR Part 75 

diluent cap procedures for non-mercury pollutants, as is allowed for Hg in 40 CFR Part 63, subpart 

UUUUU, Appendix A, would allow utilities to report more representative emissions that occur during 

startup. Commenter 20411 would also like to state its support for allowing use of a diluent cap for 

calculating emissions for EGUs subject to 40 CFR Part 60, subpart D standards.

Commenters 5834, 5840, 20417, 20418, and 20419 support the proposal to reinstate the use of the 

diluent cap, and/or provide for the use of diluent caps for non-mercury pollutants, as is allowed for Hg in 

Appendix A of subpart UUUUU. Commenters support the approach of allowing for the use of a diluent 

cap at a minimum of 5 percent CO2 and a maximum of 14 percent O2 when calculating emission rates 

for all pollutants, for any operating hour. Further, commenters support the use of default diluent gas cap 

values during periods of startup and shutdown. Commenters state without the use of diluent caps, nonrepresentative emission rates will be reported. Commenter 5840 suggests that the EPA allow use of a 

diluent cap regardless of how startup and shutdown are defined, to avoid reporting of meaningless data. 

Commenter 20421 supports the use of diluent caps which are appropriate and would be used in only 

limited situations such as startups, shutdowns, EGU trips or upsets and allow for a truer measure of the 

calculated emission rate during periods when CO2 and O2 are close to ambient conditions.

Commenter 20425 supports Commenter 20428’s recommendation to utilize the Part 75 diluent cap for 

non-normal operating periods. Commenter 20418 recommends that the EPA provide for use of the 

diluent cap during periods of startup and shutdown under the MATS Rule and encourages the EPA to 

adopt provisions consistent with 40 CFR Part 75 and allow use of the diluent cap during “any operating 

hour” when measured diluent gas values meet Part 75 criteria.

Commenter 20429 states that the fuel factors used to calculate emissions assume good combustion and 

normal operating conditions that are not applicable to SS conditions. Commenter believes that a diluent 

cap should be allowed for all pollutants reported on a heat input basis to ensure significant overreporting of emissions during SS does not occur.

Commenters 20408 and 20428 state that at low load, EGUs do not achieve complete combustion and 

actual measured CO2 concentrations are lower and O2 concentrations are higher than normal operating 

conditions, resulting in significant overstatement of emissions during startup, shutdown, and other low 

load conditions. Commenter 20428 notes that diluent gas analyzer sensitivity and stack gas stratification 

make it difficult to obtain accurate diluent measurements under low load conditions and, even more 

important, the equations used to calculate lb/MMBtu or lb/TBtu values rely on fuel factors that assume 

complete combustion and normal operating conditions. Commenter 20428 states that when an EGU is 

operating at low load, it does not achieve complete combustion and actual measured CO2 concentrations 

are lower and O2 concentrations are higher than during normal operation; these differences between 

assumed operating conditions and actual operating conditions result in significant overstatement of 
166

emissions during startup and shutdown and other low load conditions. Commenter indicates that, in 

short, the equations needed to calculate emission values for input-based standards simply were not 

designed for use under such conditions.

Commenters 20428 and 20404 state that the EPA should adopt a diluent cap for SO2, PM, HCl, and HF. 

Commenter 20428 states the EPA should extend use of diluent cap to all pollutants where emissions are 

calculated on an input basis to ensure applicable standards are achievable and to prevent significant 

over-reporting of emission rates during exempt periods. Commenter 20404 states that, alternatively, the 

EPA could exempt reporting of all pollutants during SSM periods; if reporting during SSM periods is 

required, commenter proposes a lower limit of 5 percent CO2 diluent cap in F Factor calculations used to 

generate lb/MMBtu emissions rates.

Commenters 20428 and 20387 state that the EPA recognized these issues under the Acid Rain Program 

in Part 75 and included conservative diluent caps (i.e., are designed to result in calculation of emission 

rates that are higher than what would be calculated under normal operating conditions) of 5 percent for 

CO2 and 14 percent for O2, and has since extended the diluent cap concept to other programs that rely on 

Part 75 data (e.g., CAIR) and NSPS (subparts GG, KKKK, and Eb). Commenter 20390 notes that the 

NOx Budget and Acid Rain Programs allow diluent caps of 15 percent for O2 and 5 percent for CO2, 

with no restriction on duration and that some states allow the use of the same diluent cap in reporting 

NOx and CO for compliance with NSPS and permit limits. Commenter 20428 states that the EPA

initially proposed to include diluent caps under this rule and finalized Part 75 diluent cap use for Hg 

only; the EPA failed to finalize diluent caps for other pollutants (SO2, PM, HCl, and HF) where they are 

needed. Commenter 20408 states that the EPA needs to specify that the procedures outlined in 40 CFR, 

Part 75, Appendix F, section 3.3.4.1, are appropriate and should be used for emissions monitoring 

required by MATS. Commenter 20428 states that the current proposed 3/6 definition may not provide 

sufficient time for diluent values to stabilize, and without diluent caps, EGUS will be forced to calculate, 

record, and report hourly values that are vastly overstated.

Commenter 20428 states that the EPA recognized the issue in 2011 when it initially proposed to include 

a diluent cap in the compliance calculations for periods of startup and shutdown under 40 CFR Part 63, 

subpart UUUUU. Commenter indicates that, perhaps in recognition of the different nature of the 

program, the EPA proposed a lower cap – 10.0 percent O2 or the corresponding fuel-specific CO2

concentration – than that used under Part 75. However, commenter notes that when the EPA in the final 

rule exempted periods of startup and shutdown from compliance calculations, the EPA failed to finalize 

the proposed diluent cap provision and instead allowed use of the Part 75 diluent cap, but only for Hg. 

Commenter alleges that in limiting the cap to Hg, the EPA apparently failed to consider the fact that 

recording and reporting of lb/MMBtu and lb/TBu values also is required for other pollutants (e.g., SO2, 

PM, HCl, and HF) and to analyze whether the promulgated definition of startup was sufficient to cover 

all abnormal diluent values for those other pollutants.

Commenter 20428 states that under the current rule, startup is defined as ending at the point of 

generation of electricity, and only the period up to that point is exempted from emission standards; 

However, it may take hours after the first generation of electricity for diluent gas values to arrive at

normal operating levels. Commenter alleges that because the EPA’s definitions of startup and shutdown 

as currently proposed are insufficient to exempt all periods with non-normal operation and 

corresponding non-normal diluent gas values, EGUs will be penalized in their compliance calculation of 
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non-mercury input-based emission values by having to incorporate abnormally low CO2 values and 

abnormally high O2. Commenter maintains that, at a minimum, the EPA should correct this apparent 

oversight and adopt a diluent cap for SO2, PM, HCl, and HF reported in lb/MMBtu or lb/TBtu as well.

Commenter 20428 states that, even if the EPA adopts a definition of startup that is sufficient to exempt 

the non-normal diluent values from the compliance calculation, EGUs still would be forced to calculate,

record, and for SO2, HCl, and HF report to the EPA, hourly values during the startup and shutdown 

period that are vastly overstated. Commenters 20428 and 20404 maintain that reporting values to the 

EPA that are obviously overstated can have many negative impacts for other CAA programs even if the 

values are not used in 40 CFR Part 63, subpart UUUUU, compliance calculations. Commenter 20428 

alleges that the data could skew the results of emissions modeling if those values are used as inputs, and 

otherwise overstate emissions for standard setting or other compliance calculations. Commenter 20428

notes that although EGUs will record and, where required, report actual monitored diluent values, their 

responsible officials should not be required to certify as accurate resulting lb/MMBtu or lb/TBtu values 

they believe to be significantly overstated. Commenter 20428 maintains that allowing use of a diluent 

cap for all pollutants at least would minimize the overstatement and allow responsible officials to certify 

that they are reporting values that are calculated based on a diluent cap that provides a reasonable, if 

conservative, estimation of actual emissions, rather than forcing officials to certify the accuracy of vastly 

overstated values; alternatively, the EPA could exempt those startup periods from reporting.

Commenter 20428 states that as long as the EPA adopts a reasonable startup definition, it would not 

object to use of the conservative Part 75 diluent cap to calculate and report data during non-normal 

operating periods. Commenter states that although it believes that the cap the EPA proposed in 2011 

would more accurately represent actual startup emissions by allowing use of CO2 caps that are based on 

actual startup fuel (e.g., oil or gas rather than coal), commenter also understands that using different 

diluent caps for Hg and the other pollutants for which data are reported under Part 75 could make data 

calculations inconsistent and more complicated.

Commenter 20390 notes that the proposed MATS startup and shutdown exemption language only 

allows the use of a diluent cap during the startup and shutdown period, which is a very limited time 

while the boiler is starting up on auxiliary fuel(s) and that the proposal would in essence allow for two 

different diluent caps, one for NOx rate Acid Rain reporting and another for MATS reporting of SO2, 

HCl, Hg, and HF. Commenter also notes that PM is not addressed in the MATS reporting instructions, 

and questions whether the diluent cap and electrical production rate cap would also apply to PM.

Referring to proposed April 2013 Draft Monitoring Plant Reporting Instructions for MATS, Commenter 

20390 notes the proposed diluent cap of 14 percent O2 (19 percent for IGCC) applies only for Equations 

19-5 and 19-2, and questions whether the diluent cap method would apply to all formulas, and whether 

the reporting instructions would be changed to reflect 10 percent O2 or equivalent CO2 percent (based on 

equation, CO2 percent = 20.9 – O2 percent)/FO, where FO = 0.209 * (Fd/Fc)).

Commenters 20384 and 20428 state that diluent gas cap values will prevent reporting of meaningless 

emission values caused by diluent values approaching ambient levels. Commenters 20408 and 20428 

state that responsible officials should not be required to certify as accurate the resulting values they 

believe are significantly overstated. Commenter 20428 indicates that use of diluent caps would at least 

minimize the overstatement.
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Commenter 20390 states that there are several components that make up the calculation for determining 

EGU emissions on an emission rate basis including a measurement of the flue gas volume, the pollutant 

emission, and a diluent correction factor; each of these components has inaccuracies or bias in their 

individual measurements and they are compounded when multiplied together. Commenter notes that the 

EPA, in establishment of emission limits, normally only tests at a full load steady state condition.

Commenter states that during startup, flue gas volume will go from 0 to 100 percent of the CEMS flow 

measurement and O2 will go from 20.9 to 3 percent. Commenter states one concern is the ability of 

CEMS to accurately measure flow and emissions during startup; there are no data comparing measured 

values to CEMS at low flow and or to assess to what degree does the error at low flow conditions impact 

a 30-day average. Commenter states that RATA testing on CEMS in 40 CFR Part 75 includes 3 

concentrations of gaseous pollutants at low, medium, and high to give a range of precision, however for 

flue gas volume, RATA is only certified at full load, there are no data on the accuracy over the full range 

of gas flow from initial startup to full load. Commenter states existing CEMS will not be capable of 

measuring values if monitoring is required during startup and shutdown. Commenter indicates that 

changes would need to be implemented to provide dual range analyzer systems that would include new 

analyzers, additional calibration gas and supply systems, and doubling the time/cost for quarterly and 

year-end test audits, and doubling the operating cost.

Commenter 20390 states that not correcting to a diluent of 10 percent O2 during startup and shutdown 

can cause orders of magnitude of bias and error to emission rate calculations. Commenter supports a 

default diluent of 10 percent for O2 or the fuel-specific CO2 concentration.

Commenter 20387 supports use of a diluent cap for heat input-based standards. Commenter 20389 

supports diluent gas cap values where CEMS are required to show compliance with heat input-based 

standards during startup.

Commenter 20422 states industry raises legitimate concerns over the accuracy of calculating emission 

values during periods of startup and shutdown and present theoretically legitimate concerns regarding 

artificially high emissions that might result from measuring startup emissions using CEMS, and the use 

of diluent values to report emissions makes sense so long as the EPA predicates emission reported using 

these default values on the understanding these emission values are only intended to provide an estimate 

of startup emissions and a relative sense of startup emissions between EGUs, and may not be used to 

draw conclusion about these emissions.

Commenter 20420 states that the default diluent caps in 40 CFR Part 75 should be incorporated into 

MATS for the calculation of heat input based emission rates for all pollutants. Commenter suggests that 

default diluent caps should apply whenever the measured diluent is below the CO2 cap or above the O2

cap. Commenter states that if diluent caps are not incorporated into MATS, because of the format of the 

emission rate calculation formula, lb/MMBtu (or lb/TBtu) emission rates that are calculated during 

periods of low CO2 or high O2 will be extremely high, approaching infinity.

Commenter 20420 states that because MATS requires data to be recorded during all periods of source 

operation, the lack of default diluent caps may lead to measurement mistakes for actual emission rates 

during these time periods. Commenter states that without diluent cap values at low CO2 or high O2

concentrations, EGUs will significantly over-report or under-report emissions depending on the 
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direction of the daily calibration error of the diluent gas monitor. Commenter states that the diluent cap 

represents a practical and accepted solution to the limitations of the F-factor based emission rate 

equation, and should be incorporated in the MATS rule to remedy these issues.

Commenter 20391 states that the EPA should provide for the use of a diluent O2 or CO2 cap for 

calculating compliance with input-based limits. Commenter states that during startup, or other periods 

when an EGU is at low load and does not achieve complete combustion, CO2 concentrations are lower 

than during normal operation and O2 concentrations are higher than during normal operation. 

Commenter states that equations for calculating emission values for input-based standards, however, are 

not designed to be used in these situations because they assume complete combustion and normal 

operating conditions. Commenter states that as a result, these equations overestimate emission rates 

when CO2 concentrations are very low or O2 concentrations are very high, including during startup. 

Commenter states that to ensure that EGU s that opt to use CEMS are not penalized by this 

phenomenon, the EPA must either define startup and shutdown as ending (and beginning) after (and at) 

the point when diluent concentrations reflect normal operation, or provide for a diluent “cap” for 

calculating, reporting and recording of all pollutants (SO2, HCl, PM, and HF) similar to the one provided 

in 40 CFR Part 63 subpart UUUUU, Appendix A for Hg. Commenter states that current EPA regulations 

in 40 CFR Part 75, Appendix A.3.3.4.1, allow diluent caps 5 percent CO2 and 14 percent O2) for NOx. 

Commenter states that such an approach would be consistent for the MATS rule.

Commenter 20399 states that the EPA should follow 40 CFR Part 75 guidance on use of diluent caps. 

Commenter states that the EPA’s adoption of the proposed startup definition will likely address most of 

the operating conditions where diluent caps would be utilized, but in cases where EGUs opt to not 

exclude startup and shutdown data, low load operation or load swings, and depending how the EPA 

elects to handle startups for EGUs sharing a common stack, CO2 or O2 concentrations could impact 

input-based emission rates. Commenter states that it is counterproductive to require EGUs using 

continuous emission monitors to include overestimations in their emissions averaging periods. 

Commenter states that MATS-affected EGUs currently operate CEMS according to 40 CFR Part 75.

Commenter 20399 states that by adopting diluent caps defined under Part 75 for MATS the EPA would 

allow for consistency between monitoring programs and prevent over reporting in instances where 

diluent values bias MATS emission rates. Commenter states that EGUs running at decreased load or 

firing clean fuels are emitting at a decreased rates and the MATS rule should enable EGUs to accurately 

represent that in their emissions averaging and reporting.

Commenter 20400 states that the current definition of startup causes emissions monitoring issues and,

thus, commenter supports the use of diluent capping. Commenter 20413 agrees with Commenter 20400 

comments concerning CEMS and the use of a diluent cap default value during startup. Commenter 

20400 states that for each EGU MACT limit, the EPA has provided an option for use of CEMS. 

Commenter 20400 states that some CEMS measurements are not accurate during startup, or are 

otherwise not appropriate for use in compliance calculations. Commenter 20400 strongly supports the 

use of diluent capping for Hg, HCl, and PM CEMS. Commenter 20400 is particularly concerned with: 

(1) the use of diluent (O2 or CO2) from CEMS in the equations for calculating compliance with inputbased limits (e.g., limits expressed in lb/MMBtu or lb/TBtu); (2) the use of uncorrelated data from PM 

CEMS; and (3) the effect of low generation levels on output based emissions rates.
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Commenter 20400 states that during startup, or other periods when an EGU is at low load, CO2

concentrations are significantly lower and O2 concentrations are higher than during normal operation. 

Commenter states that boiler manufacturers direct operators to use large amounts of extra combustion 

air for safety reasons until the EGU achieves normal operating conditions at higher loads. Commenter 

states that equations for calculating compliance with input-based limits, such as the “F factor” equation 

however, are not designed to be used in these situations because they assume complete combustion and 

normal operating conditions. Commenter states that as a result, these equations overstate emission rates 

when CO2 concentrations are very low or O2 concentrations are very high, including during startup 

periods. Commenter notes that by comparison, measurement of mass emissions such as tons of SO2 or 

NOx use pollutant concentration and volumetric stack flow.) Commenters state to ensure that EGUs that 

utilize CEMS for compliance are not penalized by this phenomenon, the EPA must either define startup 

(and shutdown) as ending (beginning) when diluent concentrations reflect normal operation, or provide 

for a diluent “cap” similar to the one provided in final Appendix A for Hg. (77 FR 9606, Appendix A,

section 6.2.1.2.) Commenter states that the expanded startup period proposed by Commenter 20400 

resolves this issue because a startup would conclude when CO2 concentrations are high enough, or O2

concentrations are low enough to accurately measure emissions.

Commenter 20400 states that the EPA could still elect to define startup in such a way that some EGUs 

continue to have CO2 concentrations that are significantly lower and O2 concentrations that are higher 

than during normal operation. Commenter states that in addition the EPA will likely still require the 

reporting of all CEMS data including startup and shutdown periods. Therefore, commenter recommends 

that the diluent cap definition be defined independently from the startup exclusion. Commenter states

that diluent capping is well understood under the Part 75 rules, and applies to the CO2 (or O2) data in the 

calculation of NOX lb/MMBtu already. Commenter suggests that using the same definition would 

simplify application of this rule to a common dataset being used for both programs, and decouple the use 

of diluent capping from the definition of startup exclusion under MATS.

Commenters 20400 and 20413 state that data from PM CEMS also may be inaccurate during startup and 

shutdown. Commenters state that for example, PM CEMS’ ability to monitor PM is dependent on 

correlation of the PM CEMS output to a reference method stack test (e.g., Method 5). Commenters state

that because the EPA reference methods cannot reasonably be performed under startup and shutdown 

conditions, PM CEMS are not and cannot reasonably be correlated during these periods. Commenters

state that the uncorrelated data from PM CEMS may be inaccurate for many reasons, including 

differences in stack flow (which can cause temporary stratification in the stack) and particle 

characteristics (e.g., from combustion of different fuels during startup). Commenter 20400 states that 

neither the February 16, 2012, final MATS rule nor the proposed reconsideration rule account for these 

accuracy issues. Commenters note, however, their proposed definition for a longer period startup would 

solve this problem because startup would end at a point when startup fuels such as natural gas or oil are 

either not used or constitute a low fraction of the total heat input.

Commenter 20400 states that in accordance with the final MATS rule, once a startup ends, an affected 

EGU using CEMS to demonstrate compliance must begin calculating hourly emissions rates based on 

heat input (lb/TBtu) or electrical output (lb/GWh). Commenter states that these hourly values are then 

used to generate 30-day rolling averages. Commenter states that when an EGU begins generating 

electricity during a startup, it does so at a very low percent of its total capacity. Commenter states that 

however at this time the amount of heat energy required to generate each EGU of electricity is much 
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higher than during normal operation. Commenter states that this is occurring at the same time that 

certain emissions control equipment is not operating at it full effectiveness. Commenter states that the 

combination of a higher numerator value (emissions) divided by a lower denominator value (generation) 

means that on an output basis, emissions rates during a startup are even higher than a heat input basis as 

compared to normal operation. Commenter states that, for example, during the first hour after the 

generator begins to produce electricity the reported electrical output may be 1 to 2 percent of the 

maximum electrical output yet the fuel firing rate may be greater than 10 percent of the maximum rated 

heat input. Commenter states that with output based values even higher during startup due to lower 

efficiency than heat input based values, the startup emissions are even more difficult for operators to 

average down in a 30-day rolling average. Commenter notes that extending the averaging period does 

not solve the problem because it increases the possibility of multiple startups in an averaging period. 

Commenter states that an expanded startup period would solve this problem because a startup would 

typically end only when an EGU has begun to generate a significant amount of electricity and has 

reached its normal, more energy efficient operating condition.

Commenter 20407 states that a minimum diluent cap should be included in the standard. Commenter 

states that in establishing the EGU limits the EPA has provided an option for the use of CEMS to 

monitor and report emissions values. Commenter states that for EGUs with CEMS, monitoring and 

calculation of emission values during periods of startup and shutdown, and other low-load conditions, 

present special issues. Commenter states that with respect to diluent gas measurements, when an EGU is 

at low load, CO2 concentrations are lower and O2 concentrations are higher than during normal 

operation. Commenter states that equations for calculating continuous compliance with input-based 

standards were not designed to be used in these situations because they assume complete combustion 

and normal operating conditions. Commenter states that the EPA recognized these issues when 

establishing monitoring requirements for the Acid Rain Program and promulgated provisions allowing 

reporting of a diluent “cap” in place of measured O2 or CO2 values. Commenter states that although the 

use of the cap was initially limited to periods defined as startup and shutdown, the EPA later expanded 

the concept to include any period during which measured O2 or CO2 fell below the specified cap. 

Commenter states that the use of the diluent cap is also allowed for Hg in 40 CFR Part 63, subpart 

UUUUU, Appendix A. Commenter believes that the diluent cap should also be allowed for SO2, HCl, 

and HF. Commenter states that the Part 75 diluent cap should be allowed during periods of startup,

shutdown and other low-load conditions where the O2 or CO2 concentrations fall below the specified 

cap.

Commenter 20403 supports the use of diluent caps which are appropriate and would be used in limited 

situations such as EGU trips or upsets. Commenter states that diluent caps allow for a truer measure of 

the calculated emissions during periods when CO2 and O2 are close to ambient conditions. Commenter 

states that formulas that utilize CO2 and/or O2 significantly overestimate emission when CO2 and O2

approach ambient conditions. Commenter states that the use of diluent caps would mostly be applied 

when the EGUs are already in startup and shutdowns but there are limited situations where a diluent cap 

would need to be applied and are appropriate such as an EGU trip or upset.

Response to Comment 164: Apart from allowing use of a diluent cap when calculating Hg emissions 

during periods of startup or shutdown, the final rule contained no diluent cap allowances. 

The EPA considered each comment, agreed with the commenters who suggested a need for diluent caps
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for EGUs using a common stack, and decided to allow use of default CO2 or O2 values as identified in 

Section 3.3.4.1 of Appendix F of 40 CFR Part 75 only for periods of startup or shutdown when CO2

values are below or O2 values are above default values. For non IGCC EGUs, the default CO2 value is 5 

percent and the default O2 value is 14 percent. This means that when CEMS CO2 measurements are 

below 5 percent, EGU owners or operators are allowed to use 5 percent CO2 in their calculations. When 

CEMS CO2 measurements become 5 percent or larger, EGU owners or operators will be required to use 

the CEMS CO2 measurements in their calculations. Since the startup analysis showed that CEMS CO2

measurements exceeded default values within 2 hours of generation, the EPA does not expect to find 

default values being used when startup periods end. Likewise, when CEMS O2 measurements are larger 

than 14 percent, EGU owners or operators will be able to use 14 percent O2 in their calculations. When 

CEMS O2 measurements become 14 percent or smaller, EGU owners or operators will be required to 

use the CEMS O2 measurements in their calculations. Note that IGCC EGUs will be allowed to use 1 

percent as a default CO2 value of 1 percent or 19 percent as a default O2 value. As mentioned earlier, 

default diluent gas values will be allowed for use in calculations only for periods of startup or shutdown 

when CO2 CEMS values are below or O2 CEMS values are above default values. The rule requires EGU 

owners or operators to use CO2 or O2 CEMS values for all other operating periods. While the EPA has 

no specific data or information concerning emissions during transient events outside startup or shutdown 

periods, the EPA expects the short duration of these transient events that could cause CO2 or O2 CEMS 

to be below (or above) default values to have little, if any, impact on the 30 boiler operating day rolling 

averages.

The rule retains the requirement for EGU owners or operators to report instrumental CEMS, PM CPMS, 

or sorbent trap information, as well as flow rate information during periods of startup or shutdown. Such 

information may prove useful in assessing potential emissions or operational limits in future rulemaking 

activities. 

As shown in figures submitted by commenter 20428, emissions as measured by CEMS during startup or 

shutdown periods do not appear to be “...grossly...,” “...vastly...,” or “...significantly...” overstated.

The largest hourly values are no more than 7 times the emissions limit value – nowhere near the 

“...exceedingly high, approaching infinity...” values that one commenter suggested - and the majority 

of hourly values (704/829) are near the emissions limit value.25 The values depicted in the figures do not 

contain diluent caps, which, if used, would further reduce the values. There is also no information that 

the units were complying with the work practice standard when these data were collected.

Even though the values recorded without using diluent caps do not appear overstated or problematic, the 

rule allows use of diluent caps during periods of startup or shutdown. The EPA agrees with commenter 

20428 who states that calculations based on use of a diluent cap provide reasonable estimated values of 

actual emissions for EGUs on a common stack. 

One commenter (20428) states that PM emissions recorded during those periods for both EGUs with 

common and individual stacks are about 2 to 3 times normal emissions and provides PM emissions 

 

25 See Figures 1, 2, 3, 6, 8, and 9 from Attachment I, as well as the Figure in Attachment V, submitted 

by Commenter 20428. Figure 8 is assumed to contain values measured in dry standard cubic meters and 

those values are converted to lb/MMBtu values. Note that figures which applied a diluent cap are not 

used, as it is unclear when diluent cap values were used.
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values in Figures 2 and 3 of Attachment I. It is important to remember that these data were collected 

from periods other than when the MATS rule was applicable, so we do not know whether emissions 

control devices and operational techniques required by the rule were in place during the data collection 

periods. Furthermore, the values shown are denominated in terms other than what the rule requires (i.e., 

hourly averages are shown but compliance with the rule is based on 30-boiler operating day rolling 

averages). Isokinetic conditions were maintained during that testing, and average mass acid gas emission 

rates obtained from CEMS without diluent gas correction during periods of startup and shutdown were 

found to be no more than 3 times baseline mass acid gas emission rates. In any case, we continue to 

question the accuracy of HAP emissions measurements obtained during the defined startup and 

shutdown periods.

Finally, the rule requires EGU owners or operators to identify each hour of startup or shutdown in which 

a diluent cap value is used, so that emissions data from those hours can be excluded, as appropriate, 

from compliance calculations.

Comment 165: Commenter 5830 suggests using the diluent cap values in the draft version of the Data 

Validation Clarification Document for Pennsylvania’s Continuous Source Monitoring Manual Revision 

No. 8 and 40 CFR Part 75, Appendix F: a minimum concentration of 5.0 percent CO2 or a maximum 

concentration of 14.0 percent O2 may be substituted for the measured diluent gas concentration value for 

any operating hour in which the hourly average CO2 concentration is < 5.0 percent CO2 or the hourly 

average O2 concentration is > 14.0 percent O2 for boilers.

Response to Comment 165: See previous response.

5.2 Use of default MW value

Comment 166: Commenters 20397 and 20428 state the EPA must provide a nominal default output rate 

in MW once electricity is generated. Commenter 20428 states that during the first hours of operation no 

MWs are generated and output-based emissions values cannot be calculated (denominator is zero); once 

electricity is generated MW output is low for several hours and will create unusually high output-based 

emission values. Commenter 20428 states responsible officials should not be required to certify reports 

containing such values.

Commenters 20391 and 20428 state the EPA initially proposed a default load value of 5 percent of rated 

capacity for startup and shutdown; however it failed to finalize the provision. Commenter 20428 states

the current proposed startup definition is insufficient to exclude low load operation and EGUs will 

report meaningless, grossly inflated emissions. Commenters believe 5 percent of rated capacity is the 

absolute minimum the EPA should consider and requests the EPA review data from its SO2 data set in 

lb/MWh to determine whether a higher load value, e.g., 10 percent of rated capacity, may be more 

appropriate to eliminate hourly values above the applicable numerical limits (Commenter 20428 notes

that it was unable to determine from the EPA’s Startup TSD whether 5 percent is an appropriate nominal 

value because SO2 data are only presented in lb/MMBtu and mass).

Commenter 20391 states that the EPA should establish a default load value for output-based emission 

calculations and reporting. Commenter states that during the first several hours of operation, EGUs do 

not generate any megawatts (zero output) and MW output will remain low for several hours even once 
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electricity is first generated as the EGU continues to ramp up. Commenter states that under these 

conditions, output-based emissions either cannot be calculated (if MW output is zero) or will be 

artificially high (due to low load). Commenter states that therefore, to ensure that standards that are 

based on testing at normal load can be achieved at low load, the EPA should provide a nominal default 

MW value for use in output-based compliance calculations once electricity is generated. Commenter 

states that in addition, because it is not possible to calculate an output-based emissions value when there 

is no output (i.e., no MW), the EPA should exempt periods with no electricity generation from 

calculation and reporting of output-based (lb/GWh or lb/MWh) values.

Commenter 20400 supports the use of a minimum electrical output value for purposes of calculating 

compliance with the output based standard. Commenter states that because heat input and emissions 

concentrations increase prior to the production of electricity, output-based emissions values calculated at 

the beginning of electrical output when the load is very low are extremely large due to a very small load 

value in the denominator of the output-based emission equations. Commenter states that based on a 

review of historical data, commenter believes 5 percent maximum load would be an adequate minimum 

value to prevent anomalously high data. Commenter provides two graphs from one of its EGUs to 

illustrate this situation. Commenter states that the first features a typical spike in output-based SO2

emissions at very low loads despite SO2 concentration increasing at a similar rate to load. Commenter 

states that the second graph shows the same startup with a 5 percent maximum load minimum used to 

calculate the SO2 pounds per megawatt-hour parameter.

Commenter 20428 states that, because it is not possible to calculate an output-based emissions value 

when there is no output (i.e., no MW), the EPA must exempt periods with no electricity generation from 

calculation and reporting of lb/GWh or lb/MWh values. Commenter notes that, in contrast to the 

requirement to report in lb/MMBtu or lb/TBtu as soon as fuel is combusted even if the available Btus are 

low, there are no MWs to put into the output-based calculation until electricity is generated. Commenter 

maintains that although it would be possible to calculate values for such periods using a default value, 

those values would be completely artificial and would serve no purpose; responsible officials should not 

be required to certify reports containing such values.

Commenter 20398 states that a default rate of 5 percent of the rate capacity is very low, and would likely 

cause compliance issues for most of the industry. Commenter suggests a default electrical production 

rate of 50 percent of the capacity be used for startup and shutdown. Commenter states a rate of 50 

percent is reasonable default value for most sources because they are typically base loaded and operate 

at over 80 percent capacity.

Commenter 20387 supports default electrical output rate for electric generation-based standards. 

Commenter 20389 supports a default electrical production rate where CEMS are required to show 

compliance with power output-based standards during startup. Commenter 20387 states diluent caps 

and/or default electrical output rates are necessary and appropriate, as these inaccurately impact 

compliance averages.

Commenter 20403 supports the use of a calculated electrical production rate to calculate the outputbased emission limits during startup and shutdown hours when electrical load is zero. Commenter states

that the most reasonable method is to utilize a formula to convert the steam being produced to electrical 

output.
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Commenter 20399 states that calculating output-based emission rates during periods of zero electrical 

load will be addressed with the adoption of the EPA’s proposed startup definition, but the EPA should 

adopt a default electrical load for EGUs that opt to include startup and shutdown data in their 30-day 

rolling averages. Commenter states that the EPA should utilize the 40 CFR Part 75, Appendix 

A.6.5.2.1(a)(1), defined “minimum safe, stable load.”

Commenter 20399 states that all MATS-affected EGUs are also Part 75 affected EGUs requiring a 

monitoring plan with a defined lower boundary of range of operation. Commenter states that EGUs 

should be approved to use the minimum safe, stable load value for all operations below this defined 

output. Commenter states that operations below minimum safe, stable load are generally considered 

startup, so using this value as a default electrical load allows output-based emission rates to be more 

comparable to full load operations to better represent EGU performance against the MATS standards.

Commenter 20400 states that when a startup occurs, emissions data are excluded from the time the EGU 

is first fired until the EPA-defined startup exemption period is over. Commenter notes that inevitably the 

exemption will end midway through a clock hour. Commenter proposes that the exemption apply to 

whole clock hours in which any portion is affected by the startup exclusion which avoids the problem of 

hourly data being reported in ECMPS for Hg and HCl, but using only parts of these reported data points

as the 30-day rolling average is built. Commenter maintains that applying the startup exclusion to whole 

hours will avoid discrepancy between the compliance values calculated by the data acquisition system 

(DAS), and those replicated by the EPA (and others) from hourly data. Commenter also notes that, for 

an output-based standard, there should be no calculated emissions rate during the first partial hour of 

electrical generation unless the EPA allows for use of a default minimum value.

Commenter 20400 suggests this minimum value be used whenever the load is below that value, in a 

similar manner to the application of the Part 75 diluent cap. Commenter states that in addition, it does 

not appear that there is any useful purpose in calculating an output-based emissions rate during any hour 

when there was no generation. Commenter states that that information is irrelevant to performance if 

startup emissions under the EPA’s current definition of startup or a possible expanded definition of 

startup will exclude periods prior to electrical generation from the compliance value. Commenter states

that this would only be necessary if sorbent trap systems are used and the EPA requires that the traps 

collect emissions at all times. Commenter states that in that case, it would not be possible to distinguish 

startup and shutdown emissions from normal operations, and it would be necessary to apply a default 

generation value at zero or low load to assure the EGU is not penalized in calculating an output-based 

compliance value.

Commenter 20407 states that that use of a default electrical production rate should be allowed.

Commenter said that the EPA has established an option of using electrical production rates for 

compliance with the MATS limits. Commenter states that when no megawatts are recorded during an 

operating hour, no emission value can be calculated because division by zero is not possible. 

Commenter believes a default of 5 percent electrical production, rated by capacity in megawatts, should 

be allowed during periods of startup and shutdown as was proposed in 2011.

Commenter 20408 states that the EPA needs to define a floor generation level for emission limitations 

based on lb/MWh and recommends that the EPA adopt the proposed 5 percent of rated capacity value.
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Commenter 20425 states that based on Commenter 20428’s analysis of the EPA data, the nominal 

default MW value should be 10 percent of rated output.

Commenter 20419 states that the EPA should recognize that, if it defines the end of startup as occurring 

before an EGU begins to generate electricity, which commenter does not support, the EPA must permit 

EGUs to use a default production rate value to calculate output-based emissions while the electrical load 

is zero. Commenter states that if the EPA does not adopt such a default, EGUs will be unable to 

calculate emissions in pounds per megawatt-hour because the denominator in the equation (megawatthour) will be zero.

Commenter 20429 states that that if an EGU is in operation beyond the period of the startup exemption 

at very low loads, it is still in a non-steady state startup like condition much different than normal 

operations. Commenter states that that output based emissions under these conditions calculated based 

on very low loads result in division by a very small MW value and very high calculated lb/GWh 

emission rates that do not represent actual performance of pollution control equipment. Commenter 

believes that the EPA should set a minimum default MW value for use in output-based compliance 

calculations to correct this issue.

Commenter 5830 states that a calculated value has to be used in the case of a zero electrical load 

because of the undefined result of dividing by zero when calculating output-based emission limits during 

startup and shutdown hours where the electrical load is zero. Commenter suggests converting useful 

thermal energy generated at startup and shutdown into an electrical load value of MWh, until the end of 

startup and shutdown.

Commenters 5834 and 20418 support the use of a default electrical production rate value to calculate 

output-based emission limits during startup and shutdown hours where the electrical load is zero.

Commenter 20418 states that to maintain consistency between the heat rate-based limit and the limit 

based on gross electric output, an appropriate default load rate should be equivalent to the load level that 

the average EGU reaches when producing the Part 75 diluent cap value (e.g., 5 percent CO2).

Commenter 20418 discusses default electrical production rates, based on data from its plants. 

Commenter notes that at one plant with subcritical EGUs, the default electrical production rate should be 

at least 5 percent of rated capacity to be comparable to a 5 percent CO2 diluent cap, but at another plant 

with supercritical EGUs, it should be 20 percent. Commenter notes that the primary difference between 

these plants is the type of EGU employed at each plant - one has subcritical EGUs whereas the other has 

supercritical EGUs. Commenter supports establishment of a default electrical production rate so it has 

greater flexibility in choosing a compliance option under the MATS Rule. Commenter states that the 

default electrical production rate of 5 percent of rated capacity may not appropriately account for the 

variability in EGU operation based on boiler type or other factors. Commenter encourages the EPA to 

conduct further analysis on this issue to help ensure broad availability of a default value to affected 

EGUs. At a minimum, commenter recommends that the EPA employ a default electrical production rate 

of at least 5 percent.

Commenter 5840 states that the use of a default value when load is zero is inappropriate and that the 

data collected during that time should not be included in calculations for lb/GWh emission rates. 
177

Commenter observes that there appears to be a break point between 5 and 10 percent of nameplate 

generation capacity load where the lb/GWh emission rates tend to level out from the influence of SS, 

and suggests setting a “‘percent of nameplate generating capacity”‘ as the point at which output-based 

emissions should begin to be collected.

Commenter 20390 supports a default nominal electrical production rate of 25 percent of rated capacity 

to be used when calculating emissions rates during periods of startup and shutdown or until the EGU 

achieves an steady state operating level of 10 percent O2, whichever comes first.

Commenter 20401 supports use of a default electrical output rate for non-mercury pollutants during 

startup and shutdown periods.

Response to Comment 166: The final rule had no requirements regarding default electrical output for 

EGUs sharing a common stack. Upon consideration of the comments, the EPA agrees with commenters 

who suggest a default electrical load is needed when reporting emissions on an output basis during 

startup or shutdown periods for EGUs using a common stack. The reconsidered rule provides a default 

electrical load value that EGU owners or operators will be allowed to use during periods of startup or 

shutdown to calculate emissions rates. Once the electrical load exceeds zero, use of a default value is no 

longer allowed. Moreover, use of a default electrical load is not allowed during periods other than 

startup or shutdown. As suggested by many commenters, the default electrical load will be equivalent to 

5 percent of the maximum sustainable electrical output in megawatts of an EGU, as defined in section 

6.5.2.1(a)(1) of appendix A to Part 75 and included in an EGU’s Part 75 electronic monitoring plan. As 

shown in a figure submitted by commenter 40200, this default rate is consistent with the commenter’s 

historical data and it removes anomalous high data without having to use higher default values (e.g., 10 

percent, 25 percent, 50 percent, or other elaborate calculated values) as suggested by a few commenters. 

This maximum sustainable load is either the nameplate capacity of the EGU or the highest electrical 

load observed in at least four representative quarters of EGU operation.

When used in a common stack application, the default electrical load during periods of startup or 

shutdown is 5 percent of the combined maximum sustainable electrical load of the EGUs that are in 

startup or shutdown mode during an hour in which the electrical load is zero. The default electrical load 

is allowed to be used in electrical output-based emission rate calculations (either lb/MWh or lb/GWh) 

for any hour in which the actual electrical load for an EGU venting to a common stack is zero. The EPA 

considered, but decided against, requiring measurement of thermal heat output and conversion back into 

equivalent electrical output, preferring to use a simpler approach based on already-existing requirements 

of the Acid Rain Program.

Finally, as with the diluent cap, the rule requires EGU owners or operators to identify each hour of 

startup or shutdown in which a default electrical load value is used, so that emissions data from those 

hours can be excluded, as appropriate, from compliance calculations. 

5.3 Sorbent trap monitoring systems

Comment 167: Commenters 20387, 20397, 20400, 20404, 20417, 20419, 20420, and 20428 state the 

EPA should reconsider or eliminate the requirement for using sorbent trap monitoring for Hg during 

startup and shutdown. Commenter 20387 states that although Hg may be retroactively apportioned 
178

hourly based on stack flow, the actual Hg emission rate for any given hour of the trap sampling period 

cannot be known and notes that if the sampling period were mandated to include periods of startup, the 

low diluent and/or zero generation would certainly skew the rate based compliance value upwards.

Commenter 20428 states that startup monitoring would require: dedicated sets of traps for startup and 

shutdown, a technician standing by to change the traps at the end of startup and beginning of shutdown, 

post-test leak check, and pre-test leak check. Commenter alleges that in the case of startups, such an 

exercise could result in loss of up to 45 minutes of post-startup data that otherwise would be used in the 

calculation of compliance. Commenter states that given the short duration of startup and the use of clean 

fuels during startup, such traps are unlikely to collect any meaningful data. Commenter states the same 

issues for shutdown; however, not all shutdowns are scheduled, and the precise moment electricity 

generation ceases is difficult to predict. Commenter states that the pump that pulls sample through the 

sorbent traps can be turned off, a technician must conduct a required leak check and pull the probe and 

insert new traps and but would require having a technician on call 24 hours per day.

Commenter 20390 questioned how Hg collected on the traps for the time during startup would be 

excluded from the total Hg captured. Commenters 20390 and 20419 state elevated Hg levels are possible 

during cold startup and before the scrubber or ACI/DSI systems are in operation, and will cause the 

entire trap collection mass to be higher than normal. Commenter 20390 further notes the diluent cap or 

electrical production load cap will not address this issue; the only way to exclude the data would be to 

stop pulling samples during the startup or shutdown periods.

Commenter 20429 states that that the EPA requires Hg monitoring in the final MATS rule during SS, 

but provides a SS compliance exemption for Hg during these periods. Commenter states that that for 

EGUs using sorbent traps for compliance, this would require swap out of Hg probes and traps promptly 

when each SS period begins and ends. Commenter states that this requirement would be impractical and 

discourages the use of sorbent traps for Hg monitoring, which for some EGUs may be a much more cost 

effective approach than electronic Hg analyzers. Commenter believes that the EPA should exempt EGUs 

using sorbent traps for Hg compliance from Hg monitoring requirements during SS. Commenter adds 

that there should be ample SS Hg data from EGUs using electronic Hg analyzers to provide the EPA

with the Hg emission data during SS for future needs.

Commenter 20400 states that the EPA indicated that at least one commenter suggested that traps should 

not be operated during SS periods. Commenter strongly encourages the EPA not to require the operation 

of sorbent traps during startup periods. Commenter states that sorbent trap monitoring systems are 

traditionally installed at stack elevations physically very close to the sample port. Commenter states that 

this requires travel up and down stacks which could also pose a safety risk when trap replacements are 

unplanned, especially during inclement weather. Commenter states that for the safety of its employees, 

companies will prohibit climbing a stack during periods of high winds, rain, sleet, limited light and other 

conditions. Commenter states that changing out a trap cannot necessarily be quickly accomplished. 

Commenter states that time is needed to safely travel up and down the stack. Commenter states that not 

all facilities have stack elevators and changing a trap requires manually climbing a stack. Commenter 

states that many facilities, particularly ones with single EGUs, do not have the personnel on site 24 

hours a day, 7 days a week with the necessary technical and safety training to for sorbent-trap removal 

and replacement preceding and following an unscheduled or emergency shutdown. Based on 

commenter’s experience, it could take 2 to 6 hours to remove the existing trap, leak test, warm up the 
179

entire sampling system, probe and new sorbent trap, prep the sorbent trap system for restart. Commenter 

states that an EGU outage could be delayed and/or extended while resources are secured to perform 

sorbent trap replacement. Commenter states that outage extensions would impact a company’s ability to 

provide reliable generation to the public.

Commenter 20400 states that unlike a CEMS, a sorbent trap system collects an integrated sample over 

an extended time period. Commenter states that it cannot provide real-time data because the traps have 

to be removed and analyzed remotely. Commenter states that it would therefore be impossible in a trap 

to separate the Hg data collected during startup and shutdown periods from the Hg compliance data 

obtained during routine operation. Commenter states that although startup and shutdown events are 

relatively short, if emissions data from startup and shutdown periods are included in the compliance 

calculations, this could potentially skew the compliance results. Commenter states that additionally, any 

failed startups that occur would necessitate an unplanned trap replacement.

Commenter 20400 further recommends that the EPA not require separate sorbent trap monitoring for SS

periods. Commenter states that that would require one system dedicated to SS measurement and a 

second for compliance measurement. Commenter states that two sorbent traps systems would double the 

number of port penetrations, maintenance, quarterly calibrations, RATAs, maintenance costs, and safety 

risks involved. Commenter states that use of sorbent trap system dedicated for SS would be further 

complicated when there are multiple EGUs using a common stack as to timing of when to start/stop the 

systems. Commenter states that additionally shutdown measurement could prove uniquely difficult when 

the shutdown period is unplanned and of an undetermined length. Commenter states that in fact, in many 

cases, the duration of operation during “shutdown” conditions will only be a matter of seconds, from the 

time an EGU ceases generating power to when fuel is removed from the boiler. Commenter states that it 

would make no sense to operate a sorbent trap for that small period of time. Commenter states that these 

types of shutdowns are sudden and unpredictable events, so there would be no way to start a trap system 

to capture shutdown emissions. Commenter states that also, if it is necessary to separate startup 

emissions from shutdown emissions, it would be necessary to change traps between a shutdown and the 

subsequent startup. Commenter states that that could create unnecessary delays in returning an EGU to 

service after a brief outage, for example, if an EGU were to trip from service due to some fault and 

quickly restart or if an EGU needed to come offline overnight due to low electrical demand but must be 

prepared to come back online to meet the next day’s load demand.

Commenter 20400 states that work practice standards during startup and shutdown assure Hg is 

controlled to the extent possible during these periods. Commenter states that collecting data during 

startup and shutdown will serve no purpose relative to compliance with MATS. Commenter states that if 

the EPA needs to collect startup and shutdown data to better understand performance for a future 

rulemaking, that need can be addressed through the ICR process where the EPA demonstrates the need 

and identifies a systematic plan to gather the data. Commenter states that, in fact, that should not be 

necessary because there should be sufficient data reported under MATS for startup and shutdown 

emissions from EGUs that will be operating Hg CEMS. Commenter states that if the EPA believes it is 

necessary under MATS to define some value for startup and shutdown emissions for each EGU, 

commenter recommends use of a onetime startup sampling event for the EGU to estimate emissions for 

all future startup periods. Commenter states that where a facility is comprised of multiple generators 

with like-kind boilers and AQCS systems, commenter recommends that a common emissions factor be 

utilized across those sources. Commenter states that another alternative would be to assign default 
180

emission values based on the fuel being burned each hour during the startup or shutdown and the 

controls being employed during each hour. Commenter states that those values could be established by 

the EPA or the EPA could require the utility to develop the default emissions factors similar to the 

procedures under Part 75 for data substitution.

Commenter 20408 notes that in order to measure Hg as required by the MATS rule, different monitoring 

technologies are available and acceptable for compliance with this rule. Commenter also notes that the 

EPA is requiring that Hg monitoring systems be operational during startup but that these data are not 

used when determining compliance with the 30- or 90-day rolling average emission limit. Commenter 

indicates that for sorbent traps, monitoring during a startup or shutdown is somewhat problematic 

because the sorbent trap monitoring methodology produces an integrated Hg sample typically spanning 

3 to 7 days. In order to delineate startup Hg emissions from normal operation, separate traps for SS and 

normal operation would need to be utilized due to the leak check and other Q/A requirements. 

Commenter alleges that with the sorbent trap methodology, it will be all but impossible to measure 

shutdown emissions especially in the event of a forced, unscheduled shutdown caused by a boiler system 

failure. Therefore, commenter suggests that the EPA modify how SS Hg emissions are handled for 

sorbent trap monitoring systems. Commenter recommends that the EPA not require monitoring during 

startup or shutdown, similar to what is done if quarterly stack testing is being used as with PM or HCl, 

and that the EPA utilize data from the integrated sample adjusted by the percentage of coal consumed 

(because most Hg is in the coal fuel) during startup with that typical for that sampling period.

Commenter 20420 suggests that EGUs should be required to begin collecting data with sorbent trap 

monitoring systems after startup ends, throughout normal operations, and until shutdown begins. 

Commenter states that this will allow EGUs to collect all of the emission data required to comply with 

the Hg emission limit and eliminate the problem of including startup and shutdown emissions data in Hg 

30-boiler operating day rolling average emission rates.

Response to Comment 167: After consideration of comments received on Hg monitoring during startup 

or shutdown periods using sorbent trap monitoring systems, the EPA decided that the final reconsidered 

rule will expand the Hg monitoring flexibility available to EGU owners or operators. The reconsidered 

rule contains three approaches for measuring Hg emissions during periods of startup or shutdown. In the 

first approach, EGU owners or operators will remain able to use Hg CEMS for measuring Hg emissions 

and to exclude for compliance purposes Hg emissions recorded during periods of startup or shutdown. 

The second approach relies on at least two separate sorbent monitoring systems. Although the final rule 

had no prohibition against an EGU owner or operator using one sorbent trap monitoring system for 

compliance purposes during periods other than startup or shutdown and one (or more) sorbent trap 

monitoring systems for periods of startup or shutdown through the use of a non-redundant backup 

system (per section 2.2.2 of Appendix A to subpart UUUUU), the reconsidered rule clarifies that two 

separate sorbent monitoring systems are allowed. Note that the sorbent trap monitoring system used for 

periods of startup or shutdown could use the smaller sorbent tubes required by Method 30B; use of the 

smaller volume sorbent tubes should increase detection levels, thus addressing some commenters’ 

concerns about potential non-detection. As an aside, consistent non-detection measurement is not 

necessarily a problematic outcome, because collection is to find out what the Hg emissions are during 

periods of startup or shutdown. Reliance on this second approach would address one commenter’s 

concern that Hg compliance data could not be separated from Hg data collected during startup and/or 
181

shutdown periods. When an EGU with at least two such systems (one for periods of startup or shutdown 

and the other for all other periods) entered into a startup or shutdown period, the EGU owner or operator 

could switch monitoring systems either manually or automatically. 

The third approach, relying on just one sorbent trap monitoring system for all periods of operation 

(startup, shutdown, and normal), will be identified in the reconsidered rule as a viable option for Hg 

monitoring, and, for EGU owners or operators who choose this option, the rule will allow data collected 

during startup or shutdown periods to be used for compliance purposes. EGU owners or operators may 

find that this third approach would work well for those instances in which sudden and unpredictable 

shutdown events occur, for there would be no need to swap sorbent trap monitoring systems to capture 

shutdown emissions. In addition, use of just one sorbent trap monitoring system would obviate one 

commenter’s concern over setting the proportionality rate based on flows during startup or shutdown 

periods. Consistent with the view of some commenters, the EPA expects little impact on Hg emissions 

during startup or shutdown periods, for, as explained above, clean fuels are to be used during those 

periods; default diluent and electrical output values, which tend to constrain emissions, will be available 

for use; and emissions occurring during those periods will be included in a 30- (or 90-) boiler operating 

day rolling average. As explained earlier, figures depicting Hg emissions during startup periods for an 

EGUs with individual and common stacks suggest that startup Hg emissions account for less than 5

percent of the allowable emissions limit even without complying with the final work practice. EGUs 

would need to operate such that average hourly Hg emissions for the remaining time during the quarter 

were up to 95 percent of the 30-boiler operating day emission limit.26

Along with flexibility in choosing a Hg monitoring technique comes the responsibility for carefully 

considering which approach works best for an EGU owner or operator. As part of an EGU owner or 

operator’s rubric for choosing which Hg measurement approach to use, the EGU owner or operator 

should take into account all factors, including but not limited to factors identified by commenters such 

as safety, reliability, and ease of use, as well as other factors not mentioned by commenters such as 

consequences of failure to provide necessary data and total (not just initial) system costs. As an example, 

EGU owners or operators should remember that any process operating hour for which quality assured 

Hg concentration data are not obtained is counted as an hour of monitoring system downtime, per 

section 1.4 of Appendix A to subpart UUUUU. Therefore, if an EGU owner or operator believes 

change-out of sorbent monitoring traps may take too long, other approaches may be more suitable. An 

EGU owner or operator should carefully consider all costs - not only of sorbent tubes, analyses, and 

associated labor costs, but also the potential costs of non-compliance due to data gaps.

Finally, the EPA disagrees with commenters who claim that collecting data during startup and shutdown 

will serve no purpose relative to compliance with MATS and indicated that if the EPA needs to collect 

startup and shutdown data to better understand performance for a future rulemaking, that can be 

addressed through the ICR process where the EPA demonstrates the need and identifies a systematic 

plan to gather the data. As explained in the final rule preamble,27 collection of startup and shutdown 

information will provide the EPA with information to more fully analyze the ability and appropriateness 

of establishing numeric emissions and operating limits during periods of startup or shutdown so the 

issue can be addressed as part of the ongoing 8-year review of this rule. Collection of these data as part 

 

26 See figure 9 in Attachment I and figure in Attachment V from Commenter 20428. 

27 See 77 FR 9382 (February 16, 2012).
182

of the rule will also serve to reduce, if not eliminate, future ICR requests on this topic. The EPA also 

disagrees with commenters who wish to place all startup and shutdown information on those EGU 

owners or operators who choose to use Hg CEMS, for EPA remains interested in how well sorbent tube 

monitoring systems operate during periods of startup or shutdown. Not collecting that information from 

those systems would leave a gap in the EPA’s knowledge base.

5.4 Other concerns

Comment 168: Commenter 20403 states concerns with the ongoing regulatory efforts related to air by 

the EPA (i.e., CASPR (on appeal), MATS, 1-hr SO2 NAAQS, 1-hr Ozone NOx Standards, other air 

emission rule makings and the most recent announcements to control CO2 emissions) will result in more 

stringent CO2, CO, NOx, SOx, PM, and other standards that will need to be complied with at the defined 

end of startup. Commenter states that the rush to tie startup to emissions rather than to flame or bed 

stabilization is problematic and will create greater problems over time.

Response to Comment 168: The EPA is establishing a work practice standard specific to the 

control of HAP emissions regulated under CAA section 112. The work practice itself 

acknowledges that other requirements applicable to the source may require control at different 

times. Sources are not required to comply with those other standards based on the MATS 

definitions and work practice standards, even though we believe that compliance with the work 

practice will likely lead sources to more quickly comply with other non-HAP standards because 

the controls for HAP co-control other non-HAP air pollution and the fact that clean fuels will be 

maximized throughout the defined startup period.

Comment 169: Commenter 20403 supports the use of main stack requirement if by-pass is allowed in 

emergencies.

Response to Comment 169: This comment is outside the scope of the reconsidered rule, so no response 

is required.

Comment 170: Commenter 5848 states that the EPA should make the definitions for startup and 

shutdown in the Utility NSPS, Utility MATS, and Industrial Boiler MACT rule (40 CFR 63, subpart 

DDDDD) the same or at least very similar.

Response to Comment 170: The EPA generally believes that startup and shutdown definitions for the 

subject rulemakings should reflect data and practices from the subject subcategories, particularly in the 

case of EGUs because of the considerable data and information available to the EPA; however, when 

categories are similar, as with boilers and EGUs, the Agency may consider the practices employed in the 

different categories when developing work practices standards.

Comment 171: Commenters 20409, 20423, and 5831 state that, to avoid any confusion here or in 

subsequent efforts by states or the EPA to develop permit or other compliance requirements directed at 

other CAA provisions, the final MATS SSM regulation should conclude and definitively make clear that 

the MATS SSM definition of startup should only apply to MATS SSM compliance and not for other 

emission compliance determination purposes. Commenter 20409 states that, because some of its

members are presently installing emission controls for HAP purposes, it cannot conclude that all its
183

members can achieve successful startup under the option proposed and meet their HAP emission 

compliance obligations under this proposal. Commenter 20409 states that, however, it is reasonably 

certain that at least some cooperatively owned EGUs will not be able to achieve other CAA compliance 

requirements if other emissions obligations were to commence when the proposed HAP startup period 

ends. Commenter 20409 states that the EPA’s Startup TSD supports this conclusion. Commenters 5831

and 20423 believe that an unintended consequence of this rulemaking could be that the incorporation of 

time-based work practice compliance obligation that does not relate in a real way to any permit 

condition or to any actual criteria pollutant NAAQS or NESHAP emission limitation may lead to a 

perceived compliance issue.

Commenter 20436 states that the EPA should make explicit that any decision to allow coal combustion 

prior to full operation of APCD is limited to the MATS rule and does not apply to air quality or healthbased standards incorporated in SIPs.

Response to Comment 171: The EPA believes that the definitions incorporated within this rule (40 

CFR subpart UUUUU) are only applicable to this rule unless incorporated intentionally into another rule

and, thus, commenters’ concerns are unfounded. 

Comment 172: Commenter 20419 requests that the EPA clarify how EGUs, when calculating the 30-

boiler operating day rolling average, should use CEMS data from hourly periods that include both 

minutes of normal operation and minutes of startup or shutdown. Commenter states that the MATS 

requires that EGUs choosing to comply with the emissions limits using CEMS calculate the 30-boiler 

operating day rolling average (or the alternate 90-boiler operating day rolling average for Hg) using the 

hourly average CEMS data. Commenter notes that some hourly averages may include data from both 

minutes of normal operation and minutes of startup or shutdown. Commenter states that because the 

MATS prohibits EGUs from using data recorded during startup or shutdown to demonstrate continuous 

compliance, commenter assumes that EGUs are to exclude hourly averages that include minutes of 

startup or shutdown from the calculation of the 30-boiler operating day rolling average. Commenter 

requests that the EPA confirm that this is the proper procedure for calculating the 30-boiler operating 

day rolling average to demonstrate continuous compliance at EGUs employing CEMS.

Commenter 20413 agrees that the startup and shutdown operations at an EGU are not suitable to be 

included in emissions calculations for determining compliance with emission limits because it is 

impossible to successfully and safely operate the pollution control equipment at all points during the full 

startup and shutdown periods of operation.

Response to Comment 172: The reconsidered rule requires owners or operators to identify each hour of 

startup or shutdown. As identified in the rule, any fraction of an hour in which startup or shutdown 

occurs constitutes a full hour of startup or shutdown. Except for EGU owners or operators who choose 

to demonstrate compliance with Hg emissions by including startup or shutdown emissions in their 

sorbent trap monitoring systems in compliance calculations, EGU owners or operators are to exclude 

emissions from any hour of startup or shutdown from their compliance calculations, regardless of 

pollution control device operation.

Comment 173: Commenter 5833 states that the SSM proposal will impact electric reliability and an 

overall increase in emissions could occur because of damage to air pollution control equipment.
184

Response to Comment 173: The EPA does not agree that the final work practice will lead to reliability 

concerns and the commenter has not provided compelling information to the contrary. The EPA also 

believes that the final definitions and work practices applicable during periods of startup and shutdown 

have been demonstrated at the best performing sources. EGUs that are unable to comply will have to 

make physical and/or operational changes as necessary to comply with the final rule.

5.5 Support for other commenters/comments

Comment 174: Commenters 20391, 20392, 20395, and 20397 support the comments made by 

Commenter 20428. Commenter 20418 supports the comments submitted by Commenter 20428 with 

some exceptions.

Commenter 20414 has actively commented in this rulemaking docket, including in the initial comment 

period for the EPA’ s reconsideration of certain new source and SS issues, published in the Federal 

Register on November 30, 2012. Commenter incorporates those comments, except to the extent 

modified in its current comments, and the comments filed throughout this regulatory docket, by 

reference.

Commenter 20416 supports and incorporates by reference the comments made by Commenter 20396.

Commenter 20426 fully endorses and incorporates by reference those comments submitted by 

Commenters 20396, 20397, and 20428 on this proposal.

Commenter 20430 is a member of the National Rural Electric Cooperative Association (NRECA) and 

the Gulf Coast Lignite Coalition (GCLC) and supports comments filed those organizations.

Response to Comment 174: These comments require no response as the individual comments have 

been addressed elsewhere in this document.

Comment 175: Commenter 20419 believes that its proposed changes as described in its prior comments 

would address site-specific operating constraints at many EGUs without lessening the environmental 

benefits the EPA anticipates will be achieved by the final rule.

Response to Comment 175: The EPA believes that commenter’s issues have been addressed elsewhere 

in this document.

5.6 Out of Scope

Comment 176: Commenter 20411 states that, although the EPA did not ask for comments on quarterly 

stack testing in this reconsideration, it would like to restate the comments made in a previous 

reconsideration. Commenter states that the EPA incorrectly concludes that many existing affected coalfueled EGUs will be using CEMS to monitor their PM emissions and therefore will have no interest in

demonstrating compliance through quarterly PM stack tests. Commenter states that the approach to 

compliance with PM requirements is often not the same as the approach for Hg because there are many 

EGUs with very low PM levels for which there is no great need for the “frequent feedback” of PM 
185

CEMS. Commenter states that in such cases, it is still appropriate to utilize quarterly stack testing rather 

than CEMS as the method for demonstrating compliance with the filterable PM limit.

Commenter 20411 believes it is important that the EPA retain the quarterly stack testing compliance 

option. Commenter states that it is appropriate for low-PM emitting EGUs to utilize quarterly stack 

testing. Commenter states that additionally, the lack of reliable HCl CEMS will necessitate that EGUs 

without SO2 controls perform quarterly stack testing to show compliance with the HCl limit. Commenter 

states that, therefore, it is its intent to utilize quarterly stack testing for showing compliance with the PM 

and HCl limits at its existing EGUs and it is planning to continue to do so into the future for MATS 

compliance. Therefore, commenter requests that the EPA retain this option for PM compliance 

monitoring.

Response to Comment 176: Quarterly stack testing for new coal- and oil-fired EGUs was not at issue 

in this reconsideration (it was addressed in the final reconsideration of the new-source emission limits; 

see 78 FR 24073, April 24, 2013) and, thus, no response is required.
186

Table 3. List of Commenters on November 30, 2012, Proposal28

Commenter Name Commenter Organization EPA Docket ID

Terry M. Hogan Wabash Valley Power Association, 

Inc.

EPA-HQ-OAR-2009-0234-

20243

Eric Redman Summit Power EPA-HQ-OAR-2009-0234-

20245

Bart Sponseller Wisconsin Department of Natural 

Resources (WDNR)

EPA-HQ-OAR-2009-0234-

20246

Claire M. Olson Basin Electric Power Cooperative EPA-HQ-OAR-2009-0234-

20247

Walter Stone NRG Energy, Inc. EPA-HQ-OAR-2009-0234-

20248

Bob Holmes Omaha Public Power District (OPPD) EPA-HQ-OAR-2009-0234-

20251

Lisa Jaeger Edgecombe Genco LLC and Spruance 

Genco LLC

EPA-HQ-OAR-2009-0234-

20252

Joe L. Citta, Jr. Nebraska Public Power District 

(NPPD)

EPA-HQ-OAR-2009-0234-

20254

Patrick O’Loughlin Buckeye Power, Inc. EPA-HQ-OAR-2009-0234-

20255

Raymond L. Evans FirstEnergy Corp. EPA-HQ-OAR-2009-0234-

20256

Kenneth J. Anderson Ameren Corporation EPA-HQ-OAR-2009-0234-

20257

Mark Thoma Otter Tail Power Company EPA-HQ-OAR-2009-0234-

20262

PJ Becker City of Springfield, City Water Light 

and Power

EPA-HQ-OAR-2009-0234-

20267

Debra J. Jezouit

Baker Botts L.L.P. et al. on behalf of 

The Class of ‘85 Regulatory Response 

Group

EPA-HQ-OAR-2009-0234-

20269

Chris M. Hobson Southern Company EPA-HQ-OAR-2009-0234-

20270

Cathy S. Woollums MidAmerican Energy Holdings 

Company

EPA-HQ-OAR-2009-0234-

20271

Jay Hudson Santee Cooper EPA-HQ-OAR-2009-0234-

20272

John A. Riley Bracewell & Giuliani LLP, on behalf 

of Las Brisas Energy Center, LLC

EPA-HQ-OAR-2009-0234-

20273

Michael J. Nasi Jackson Walker, LLP, on behalf of 

Gulf Coast Lignite Coalition (GCLC)

EPA-HQ-OAR-2009-0234-

20275

 

28 Only those commenters providing comment on the startup/shutdown reconsideration issues are listed.
187

Jon Madison Montana-Dakota Utilities Company EPA-HQ-OAR-2009-0234-

20276

Greg F. Myers Consumers Energy EPA-HQ-OAR-2009-0234-

20277

Myra Glover Entergy Services, Inc. EPA-HQ-OAR-2009-0234-

20279

Kelly J. Barr Salt River Project (SRP) EPA-HQ-OAR-2009-0234-

20280

J. Michael Geers Duke Energy EPA-HQ-OAR-2009-0234-

20281

Lee B. Zeugin, et al. Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-

20282

Stephen Fotis Generators for Clean Air (GCA) EPA-HQ-OAR-2009-0234-

20283, -20288

Jeffrey A. McNelly ARIPPA EPA-HQ-OAR-2009-0234-

20285

Zak Covar Texas Commission on Environmental 

Quality (TCEQ)

EPA-HQ-OAR-2009-0234-

20286

Chet Thompson Crowell & Moring LLP, on behalf of 

Homer City Generation, L.P.

EPA-HQ-OAR-2009-0234-

20287

Henry E. Eby Lower Colorado River Authority 

(LCRA)

EPA-HQ-OAR-2009-0234-

20289

Paul M. Ling Kansas City Power & Light Company 

(KCP&L)

EPA-HQ-OAR-2009-0234-

20291

J. Michael Brown Ohio Valley Electric Corporation EPA-HQ-OAR-2009-0234-

20294

Quinlan J. Shea Edison Electric Institute (EEI) EPA-HQ-OAR-2009-0234-

20295

Brian Brazil TransAlta Centralia Generation, LLC EPA-HQ-OAR-2009-0234-

20297

Norman Schilling General Electric Company (GE) EPA-HQ-OAR-2009-0234-

20299

Michael L. Krancer Pennsylvania Department of 

Environmental Protection (PDEP)

EPA-HQ-OAR-2009-0234-

20302

Joseph G. Eutizi San Miguel Electric Cooperative EPA-HQ-OAR-2009-0234-

20303

Melvin E. Keener Coalition for Responsible Waste 

Incineration (CRWI)

EPA-HQ-OAR-2009-0234-

20304

David Woodsmall Sierra Club, et al. EPA-HQ-OAR-2009-0234-

20305

Gregory Ryan DTE Energy EPA-HQ-OAR-2009-0234-

20306
188

John M. McManus American Electric Power (AEP) EPA-HQ-OAR-2009-0234-

20308

Berdell Knowles JEA EPA-HQ-OAR-2009-0234-

20321

Joaquin C. Flores Guam Power Authority EPA-HQ-OAR-2011-0044-

5785

Megan Murphy PPL Services Corporation EPA-HQ-OAR-2011-0044-

5803
189

Table 4. List of Commenters on June 25, 2013, Comment Period Reopening

Commenter Name Commenter Organization EPA Docket ID

John T. Graves Minnkota Power Cooperative, Inc. EPA-HQ-OAR-2009-0234-

20384

P. J. Becker City of Springfield, City Water Light & 

Power (CWLP)

EPA-HQ-OAR-2009-0234-

20387

John A. Paul Regional Air Pollution Control Agency 

of Dayton, Ohio (RAPCA)

EPA-HQ-OAR-2009-0234-

20388

Mark J. Sedlacek Los Angeles Department of Water and 

Power (LADWP)

EPA-HQ-OAR-2009-0234-

20389

Betsy Natz Institute of Clean Air Companies 

(ICAC)

EPA-HQ-OAR-2009-0234-

20390

Pamela F. Faggert Dominion Resources Services, Inc. EPA-HQ-OAR-2009-0234-

20391

Barbara A. Walz Tri-State Generation & Transmission 

Association, Inc.

EPA-HQ-OAR-2009-0234-

20392, 20394

Jay Hudson Santee Cooper EPA-HQ-OAR-2009-0234-

20393

Chris M. Hobson Southern Company EPA-HQ-OAR-2009-0234-

20395, -20412

Quinlan J. Shea, III Edison Electric Institute (EEI) EPA-HQ-OAR-2009-0234-

20396

John M. McManus American Electric Power (AEP) EPA-HQ-OAR-2009-0234-

20397

Grant Rodway Bison Engineering, Inc. EPA-HQ-OAR-2009-0234-

20398

Brian W. Green NRG Energy, Inc. EPA-HQ-OAR-2009-0234-

20399

J. Michael Geers Duke Energy EPA-HQ-OAR-2009-0234-

20400

Brittany Barrientos Kansas City Board of Public Utilities EPA-HQ-OAR-2009-0234-

20401

Lorraine Krupa Gershman American Chemistry Council EPA-HQ-OAR-2009-0234-

20402

Jeffrey A. McNelly ARIPPA EPA-HQ-OAR-2009-0234-

20403

Paul M. Ling. Kansas City Power and Light EPA-HQ-OAR-2009-0924-

20404

Scott J. Nally Ohio EPA EPA-HQ-OAR-2009-0234-

20405

Brian Brazil TransAlta EPA-HQ-OAR-2009-0234-

20406
190

Cathy S. Woollums MidAmerican Energy Holdings 

Company

EPA-HQ-OAR-2009-0234-

20407

Ken Anderson Ameren Corporation EPA-HQ-OAR-2009-0234-

20408

Rae E. Cronmiller National Rural Electric Cooperative 

Association (NRECA)

EPA-HQ-OAR-2009-0234-

20409

Bob Holmes Omaha Public Power District (OPPD) EPA-HQ-OAR-2009-0234-

20410

Joe L. Citta, Jr. Nebraska Public Power District 

(NPPD)

EPA-HQ-OAR-2009-0234-

20411

Jeff Burkett The Empire District Electric Company EPA-HQ-OAR-2009-0234-

20413

Michael J. Nasi Gulf Coast Lignite Coalition (GCLC) EPA-HQ-OAR-2009-0234-

20414

Lisa M. Jaeger Council of Industrial Boiler Owners 

(CIBO)

EPA-HQ-OAR-2009-0234-

20415

Jon Madison Montana Dakota Utilities Co. EPA-HQ-OAR-2009-0234-

20416

Megan Murphy PPL Services Corporation EPA-HQ-OAR-2009-0234-

20417

Kara M. Montalvo Salt River Project Agricultural 

Improvement and Power District (SRP)

EPA-HQ-OAR-2009-0234-

20418

Debra J. Jezouit and 

Allison Watkins

Class of ‘85 Regulatory Response

Group

EPA-HQ-OAR-2009-0234-

20419

Jerry Purvis East Kentucky Power Cooperative EPA-HQ-OAR-2009-0234-

20420

Lisa M. Jaeger

Bracewell & Giuliani LLP, on behalf 

of Edgecombe Genco LLC, and 

Spruance Genco LLC

EPA-HQ-OAR-2009-0234-

20421

Whitney Ferrell Environmental Integrity Project EPA-HQ-OAR-2009-0234-

20422

Claire M. Olson Basin Electric Power Cooperative EPA-HQ-OAR-2009-0234-

20423

Bill Mathews Cleco Power LLC EPA-HQ-OAR-2009-0234-

20424

Raymond L. Evans FirstEnergy EPA-HQ-OAR-2009-0234-

20425

J. Michael Brown

Ohio Valley Electric Corporation 

(OVEC)/ Indiana-Kentucky Electric 

Corporation (IKEC)

EPA-HQ-OAR-2009-0234-

20426

Sanjay Narayan Sierra Club et al. EPA-HQ-OAR-2009-0234-

20427, 20438

Lee B. Zeugin et al. Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-

20428, -20433, -20437
191

John W. Myers Tennessee Valley Authority (TVA) EPA-HQ-OAR-2009-0234-

20429

Joseph G. Eutizi San Miguel Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-

20430

John M. Ross Northern Indiana Public Service 

Company (NIPSCO)

EPA-HQ-OAR-2009-0234-

20431

Eric Schaeffer Environmental Integrity Project EPA-HQ-OAR-2009-0234-

20436

Vincent Brisini Pennsylvania Department of 

Environmental Protection

EPA-HQ-OAR-2011-0044-

5830

Wayne E. Penrod Sunflower Electric Power Corporation EPA-HQ-OAR-2011-0044-

5831

Thomas N. Effinger SCANA EPA-HQ-OAR-2011-0044-

5833

Henry Eby Lower Colorado River Authority 

(LCRA)

EPA-HQ-OAR-2011-0044-

5834

Kimberly D. Mireles Luminant EPA-HQ-OAR-2011-0044-

5840

David A. Buff Golder Associates on behalf of New 

Hope Power Company

EPA-HQ-OAR-2011-0044-

5848