March 9, 2015

EPA Docket Center Environmental Protection Agency Mailcode 2822T 1200 Pennsylvania Ave., NW Washington, DC 20460

RE: Docket ID No. EPA–HQ–OAR–2002-0058, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (80 Fed. Reg. 3090 (Jan. 21, 2015))

A coalition of the following industry organizations hereby submits comments on the

Proposed National Emission Standards for Hazardous Air Pollutants for Major Sources:

Industrial, Commercial, and Industrial Boilers and Process Heaters (80 Fed. Reg. 3090

(Jan. 21, 2015)).

American Forest & Paper Association

American Fuel and Petrochemical Manufacturers

American Iron and Steel Institute

American Petroleum Institute

American Wood Council

Biomass Power Association

National Association of Manufacturers

National Oilseed Processors Association

Southeast Lumber Manufacturers Association

Treated Wood Council

The organizations’ member companies own and operate hundreds of boilers and process

heaters that are subject to the Boiler MACT. Several of the organizations and several of

their member companies submitted extensive comments on the June 4, 2010 proposed

Boiler MACT and the December 3, 2011 proposed reconsideration rule. We appreciate

the fact that EPA made numerous changes to final Boiler MACT rule in response to public

comments and is proposing additional changes to make important clarifications.

In the current rulemaking, it is important to finalize startup and shutdown requirements

that are appropriate for the various designs of industrial boilers and process heaters

regulated under this rule, and not designed based on data from EGUs (which are

fundamentally different than industrial boilers). We are also concerned with the proposed

elimination of the malfunction affirmative defense. The proposal does not provide an

adequate explanation of how this critical part of the rule can be eliminated without

assessing whether and how the remaining standards might need to be revised. The DC

Circuit has made it clear that some accommodation for malfunctions must be provided in

technology-based standards, such as the Boiler MACT. Without more, eliminating the

affirmative defense violates this basic obligation.

Thank you for your consideration of the important issues included in these comments.

Please feel free to contact Tim Hunt at 202-463-2588 on my staff as a representative of

the coalition if you have questions or need more information.

Sincerely,

Paul Noe Vice President for Public Policy American Forest & Paper Association

On behalf of the listed trade associations

cc: J. McCabe T. Powers P. Tsirigotis J. Eddinger

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Table of Contents

I. Executive Summary .............................................................................................. 1

II. Comments on Startup and Shutdown Changes ................................................. 2 A. Startup and Shutdown Definitions .......................................................................... 2

1. Startup Definition ................................................................................ 2 2. Useful Thermal Energy ...................................................................... 4

3. Alternate Startup Definition ................................................................ 5 4. Shutdown Definition ........................................................................... 7

B. Startup and Shutdown Work Practices ................................................................... 8 1. Clean Fuels ........................................................................................ 8

2. Dry Biomass is a Clean Fuel .............................................................. 8 3. Startup Clarification Needed .............................................................. 9 4. Time to Engage PM Controls ............................................................. 9

C. Startup and Common Stacks ............................................................................... 13 D. Additional Monitoring and Recordkeeping During Startup and Shutdown ............. 14

III. Malfunctions and Affirmative Defense .............................................................. 15 A. Elimination of Affirmative Defense for Malfunctions .............................................. 15 B. EPA Is Required To Take Malfunctions into Account when Setting MACT

Standards ............................................................................................................ 17 C. Tools for Accounting for Malfunctions in the Standards Once the Affirmative

Defense Is Eliminated .......................................................................................... 19

IV. PM CPMS Requirements ..................................................................................... 22 A. An Exceedance of an Operating Parameter Should not be a Presumptive Violation

of the Standard .................................................................................................... 22 B. Certification of PM CPMS .................................................................................... 23

V. Minimum CO Limits ............................................................................................. 23

VI. Comments on Technical Changes ..................................................................... 25 A. Changes to Output Based Limits .......................................................................... 25 B. Load Operating Parameter ................................................................................... 25 C. O2 Trim System Requirements ............................................................................. 28 D. Fuel Sampling Requirements and Compliance .................................................... 28 E. pH Performance Evaluation – Proposed Change to “Calibrate” ............................ 31 F. Timing for Compliance After Modifications in 63.7495(h) ..................................... 31 G. Applicability to Gas-Fired EGU’s .......................................................................... 31 H. Clarification Regarding Submittal of Other Gas 1 Fuel Sampling Plan ................. 31 I. Load Fraction ....................................................................................................... 32 J. Hybrid Suspension Grate CO limit ....................................................................... 32 K. Clarification is Needed on Reporting 30-day and 10-day Average Values for CEMS

and CPMS ........................................................................................................... 32 L. Opacity Operating Parameter Limit ...................................................................... 32 M. Additional Technical Edits Requested .................................................................. 34

VII. Conclusion ........................................................................................................... 36

Attachment 1. Excerpt from ESP Operating Manual .................................................. 37

Attachment 2. Excerpt from Recently Installed ESP Operating Manual ................... 41

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I. Executive Summary

The companies our organizations represent are committed to operating in an

environmentally responsible and sustainable manner. They are hard at work

implementing emissions reductions and monitoring, recordkeeping, and reporting

systems to comply with Boiler MACT. We appreciate that EPA reset the compliance

clock for this complex rule when the prior final reconsideration rule was promulgated on

January 31, 2013. However, with the requirements of the rule in flux and the

compliance date of January 31, 2016 quickly approaching, our members are worried

that these proposed changes will not be finalized in time for them to adequately

implement changes to their systems. We also appreciate many of the clarifications that

EPA is making with this proposal. But, we remain concerned that the details

surrounding startup, shutdown, and malfunction remain in flux as the existing source

compliance deadline approaches and permitting authorities are not granting compliance

extensions based on regulatory uncertainty. We urge EPA to carefully consider our

comments but also to finalize the rule changes as expeditiously as possible so that clear

and workable rules are in place with adequate time for facilities to make adjustments

based on the promulgated final reconsideration rule language prior to the compliance

deadline.

We are concerned that EPA has proposed to eliminate the malfunction affirmative

defense provisions without providing some other accommodation for malfunctions. The

affirmative defense was a key element of EPA’s explanation for why it was lawful for the

Agency to promulgate MACT standards that apply during malfunctions but that do not

reflect what is achievable with available technology during malfunctions. EPA must

reassess the appropriateness of the emission standards and how boiler and process

heater operators will be affected and provide appropriate alternative measures prior to

removing the affirmative defense provisions from the rule.

It is important to point out that facilities are already motivated to minimize the duration of

startup and shutdown in the absence of specific regulatory requirements. Startup,

shutdown, and even malfunction conditions represent performance inefficiencies, and

thus money loss. Operators want to reach and maintain a stable operating condition of

the boiler/process heater and the processes using energy as quickly as possible, and

stable operation of plant operations results in lower HAP emissions, but safety and

proper operation of equipment must take precedence. We hope that the information

provided in our comments helps EPA understand the complexities associated with

startup of industrial boilers and process heaters and that a one-size-fits-all approach is

not feasible. The provisions around startup and shutdown are a critical piece of the rule

as a whole and our comments provide important additional clarifications that EPA

should implement to allow facilities an assurance that they can safely comply with these

provisions.

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II. Comments on Startup and Shutdown Changes

The boiler/process heater emission standards apply at all times, except during periods

of startup and shutdown, during which times facilities are required to comply with work

practices. A work practice approach during startup and shutdown is appropriate, as we

have stated in comments on the startup and shutdown requirements as they have

evolved in the various versions of the rule. We continue to believe that for worker

safety, equipment protection, and overall environmental benefit, the best way to

implement startup and shutdown work practices is through a site-specific approach,

given the myriad designs and applications of industrial boilers and process heaters.

However, we provide comments on the approach that EPA proposes below.

We note that the description of the additional requirements for startup in the preamble is

much more expansive and burdensome than what is actually included in the rule. For

example, the preamble at 80 FR 3095 spells out specific elements that must be

included in a petition to extend the PM control device startup time. However, those

specific requirements are not contained in Table 3 of the proposed rule. Given the

inconsistencies between the preamble and the proposed rule text, we are not able to

reasonably ascertain the rules that EPA actually intended to propose here. For

purposes of preparing these comments, we have assumed that the proposed rule text is

the accurate indicator of EPA’s intentions.

A. Startup and Shutdown Definitions

1. Startup Definition

EPA has proposed to modify the definition of startup by adding an alternate definition of

the end of startup. We previously provided comments that the current definition of the

end of startup (“when any of the steam or heat from the boiler or process heater is

supplied for heating, and/or producing electricity, or for any other purpose”) is

unworkable. Adding a second definition does not address the fact that the first definition

is not workable; there is significant effort associated with selecting the second definition

and the requirements are substantially different with respect to timing to engage

controls. The act of supplying heat, steam, or electricity does not represent the

functional end of the startup period. Some processes are designed such that

downstream equipment receives heat and/or steam when fuel is being burned during

startup of the boilers and/or process heaters. For example, as a boiler that provides

steam to a lumber kiln is starting up, initial low-pressure steam is used for preheating

the metal steam lines long before steam at rated temperature and pressure is available.

This preheating is necessary to avoid a rush of steam that can cause the metal to

expand too quickly, resulting in catastrophic damage. This type of operating practice

represents efficient use of energy during startup (e.g., instead of venting or wasting the

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heat) to prepare/preheat process equipment and is a practice EPA should not

discourage.

Above all, the boiler/process heater operator’s primary concern during startup is safety,

both from a personnel and an equipment perspective. The startup definition must be

consistent with the operational reality that startup procedures must ensure that the

equipment is brought up to normal operating conditions in a safe manner using

procedures as recommended by the boiler, pollution control equipment, and process

equipment suppliers and as required by codes for the prevention of fires and explosions

published by NFPA.[1] Any viable definition of startup must also provide that the startup

period ends when the boiler/process heater and its controls are fully functional and are

supplying steam or heat to the processes and/or building requiring the energy. In many

cases, the stable operation of the boiler or process heater is tied to whether the process

being served has reached stable operation. The procedures and the time necessary to

complete a startup are site specific, and vary by boiler fuel, design, and control

technique. The end of startup occurs when safe, stable, steady-state boiler and

process operating conditions are reached, after emissions controls are properly

operating. As EPA indicates in the preamble, industry provided extensive information

supporting the addition of ESPs to the list of equipment included in the first startup

definition that must be started as expeditiously as possible. Additional information

related to startup of ESPs is provided again in these comments.

EPA attempts to address our concerns with the current startup definition by proposing

an alternate definition of the end of startup at 40 CFR 63.7575:

(2)The period in which operation of a boiler or process heater is initiated

for any purpose. Startup begins with either the firing of fuel in a boiler or

process heater for the purpose of supplying useful thermal energy (such

as steam or heat) for heating, cooling or process purposes, or producing

electricity (other than the first-ever firing of fuel in a boiler or process

heater following construction of the boiler or process heater), or the firing

of fuel in a boiler or process heater for any purpose after a shutdown

event. Startup ends four hours after when the boiler or process heater

makes useful thermal energy (such as heat or steam) for heating, cooling,

or process purposes, or generates electricity, whichever is earlier.

As an initial matter, the proposed rule text in Table 3 to Subpart DDDDD makes it clear

that the boiler owner/operator gets to decide which of the alternative definitions of

startup to use (“If you choose to comply using definition (2) of “startup” ….”). 80 Fed.

[1]

NFPA – National Fire Protection Association - The world's leading advocate of fire prevention and an authoritative

source on public safety, NFPA develops, publishes, and disseminates more than 300 consensus codes and standards intended to minimize the possibility and effects of fire and other risks.

4

Reg. at 3120 (emphasis added). However, the proposed definition of startup does not

include similar language. To avoid any confusion as to who gets to decide which

startup definition to use and to provide consistency with the proposed rule text in

Table 3, the definition of startup should be amended to clearly state that the boiler

owner/operator has the sole discretion to decide which alternative definition to apply.

This could be accomplished by making the following change to the proposed definition

of startup: “Startup means: At the sole discretion of the owner or operator, (1)

Either the first-ever …..”

2. Useful Thermal Energy

EPA has also proposed to define “useful thermal energy” at 40 CFR 63.7575 as follows:

“energy (i.e., steam, hot water, or process heat) that meets the minimum operating

temperature and/or pressure required by any energy use system that uses energy

provided by the affected boiler or process heater.” EPA needs to clarify this definition.

Unlike utility boilers, industrial boilers often supply “useful thermal energy” to multiple

end uses, including combined heat and power, such that “useful thermal energy” may

be provided long before the boiler system is operating in a stable or normal manner.

We believe that any viable definition of “useful thermal energy” must incorporate a

primary purpose component that assures that the four-hour startup period is not

triggered until useful energy is supplied to the most demanding end use (e.g., producing

a final product). Otherwise, the startup of a boiler in conjunction with a production

process system that is starting up could experience multiple disruptive events that

would arbitrarily, per the regulatory startup and/or shutdown definitions, cause the boiler

to cycle between those defined regulatory modes in a way that the facility cannot

completely comply.

We would note that flow is also an important parameter for determining whether the unit

is providing useful thermal energy, as EPA states in the preamble: “industrial boilers

should be considered subject to applicable standards at all times steam of the proper

pressure, temperature and flow rate is being supplied to a common header system or

energy user(s) for use as either process steam or for the cogeneration of electricity.”

See 80 FR 3093. We suggest the following clarifications to emphasize that startup has

ended when the boiler or process heater is supplying steam or heat at the proper

temperature, pressure, and flow to the processes (energy use systems) being served,

not immediately after making any amount of heat for any incidental purpose, such as

warming up piping (which including the word “heating” could imply).

Change: Startup ends four hours after when the boiler or process heater makes

useful thermal energy (such as heat or steam) for heating, cooling, or process

purposes, or generates electricity, whichever is earlier.

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To: Startup ends four hours after when the boiler or process heater is supplying

useful thermal energy (such as heat or steam) or generates electricity, whichever

is earlier.

Change: Useful thermal energy means energy (i.e., steam, hot water, or process

heat) that meets the minimum operating temperature and/or pressure required by

any energy use system that uses energy provided by the affected boiler or

process heater.

To: Useful thermal energy means energy (i.e., steam, hot water, or process heat)

that meets the minimum operating temperature, pressure and/or flow required by

all energy use systems that use energy provided by the affected boiler or process

heater.

The first definition of the end of startup could likewise be improved by incorporating the

“useful thermal energy” concept. Instead of defining the end of startup under the first

definition as “when any of the steam or heat from the boiler or process heater is

supplied for heating, and/or producing electricity, or for any other purpose,” EPA should

revise this definition as: “Startup ends when useful thermal energy from the boiler or

process heater is supplied for heating, and/or producing electricity, or for any other

purpose.”

3. Alternate Startup Definition

EPA chose the 4 hours included in the second startup definition not based on

information provided by owners of industrial boilers and process heaters but based on

information for EGUs. The preamble states: “Using hour-by-hour emissions and

operation data for EGUs reported to the agency under the Acid Rain Program, we found

that controls used on the best performing 12 percent EGUs reach stable operation

within 4 hours after the start of electricity generation.” EPA analyzed NOx and SO2

controls on EGU’s (SCR and FGD), but PM and CO emissions are also at issue and

must be considered. The EPA’s November 2014 document “Assessment of startup

period at coal-fired electric generating units – Revised” admits that EPA did not review

any data for PM controls in establishing the startup definitions. EPA also excluded any

EGUs cogenerating steam from their analysis. The utility industry’s own comments in

the January 20, 2015 petition for reconsideration of the MATS rule submitted by the

Utility Air Regulatory Group indicate that they cannot replicate EPA’s analysis of startup

times of EGUs.

Industrial boilers and process heaters do not all operate similarly to EGUs. The sole

purpose of an EGU is to generate electricity as soon as possible. Industrial boilers and

process heaters must start up in concert with the processes that use the energy they

supply. For a facility as complex as a pulp and paper mill with multiple process

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operations that need heat, steam, and electricity to operate and must start up in a

certain sequence, the goal is not to start up the boilers as fast as possible, the goal is to

match the operation of the boilers with the needs of the process and start up the entire

facility in a safe and efficient manner to make quality product as soon as possible.

Thus, the time until the start of electricity generation – the key factor in EPA’s startup

analysis under MATS – is not a factor that is generally relevant in assessing an

appropriate startup period for industrial boilers.

We appreciate EPA’s proposal to allow us to define “useful thermal energy” on a site-

specific basis. However, EPA should examine information on the time it takes industrial

units and their controls to achieve safe and stable operation during startup and should

not rely solely on its data for EGU’s. We understand that the Council of Industrial Boiler

Owners (CIBO) provided information to EPA on startup times and that information

indicates that the time to reach stable operation varies greatly by boiler/process heater

fuel, design, and purpose. Although the preamble (see 80 FR 3094) indicates that

CIBO only provided information on 13 units, they actually provided a summary table that

covered 76 units of varying design, fuel, and air pollution control characteristics. CIBO

is providing additional information on the units in their survey in their comments.

Because there are many more designs of industrial boilers and process heaters than

there are EGU designs, a fixed 4 hour period is not appropriate or feasible for all

industrial boilers. For example, for fluidized bed boilers, the sand media must be

heated consistently and thoroughly during the startup period, which takes time. An

examination of the EGU information that EPA used to set the proposed 4-hour time

period (“Assessment of startup period at coal-fired electric generating units – Revised”)

shows that a time of at least 10 hours is more appropriate for fluidized bed units (see

Page 6) and a time of at least 6 hours is more appropriate across all designs (see

Figure 2 – EGUs fired fossil fuel for 6 hours prior to electricity generation for the highest

number of startups). Time to reach a stable level of generation for the pulverized coal

(PC) units examined was on the order of 12 hours (see Figures 4 and 5). The average

time to reach a stable, controlled SO2 emission rate for PC units with dry flue gas

desulfurization and the time to reach a stable, controlled NOx emission rate for PC units

with SCR was about 20 hours (see Figures 16 and 21). Based on the data and

recommendations submitted by CIBO and the other information EPA has already

reviewed, EPA should allow a longer time than 4 hours for startup. EPA could even

establish a separate startup time for each industrial boiler subcategory that reflects the

subcategory-specific data and characteristics.

The proposed startup provisions unambiguously are work practice standards under §

112(h) and not emission standards under § 112(d). As such, the analytical methods for

determining MACT floors under § 112(d) (e.g., “average emissions limitation achieved”

by the better performers) do not and cannot apply in formulating the § 112(h)-based

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startup provisions. Yet, EPA explains in its supporting analysis for the proposed 4-hour

startup period that, “CAA section 112 requires the EPA to establish standards based on

the average of the best performing 12 percent of EGUs.”1 EPA clearly is mistaken in

asserting that it must adhere to a 4-hour period because it effectively represents the §

112(h) “floor” for the startup work practice. In fact, because § 112(h) plainly does not

require EPA to apply the § 112(d) floor provisions, EPA has much broader legal

discretion that it asserts as the basis for the proposed Boiler MACT startup provisions.2

It is well within EPA’s authority to provide for a longer startup period – even though it

may not be the average startup period of the so-called “best performers” for purposes of

startup – if other relevant factors (such as those described above) provide a reasonable

basis for selecting a different time period.

4. Shutdown Definition

In any event, EPA has appropriately responded to comments suggesting clarifications

are needed to the definition of shutdown and has proposed several changes. The

current definition of shutdown is problematic for units firing solid fuels on a grate or in a

fluidized bed combustor where the residual material in the unit keeps burning after fuel

feed to the unit is stopped. In this case fuel is still burning (“being fired” or combusted)

in the unit despite the fact that load reduction is occurring, additional fuel is not being

fed, and the shutdown process has clearly begun.

The definition of shutdown does not address all conditions that will be typical of

boiler/process heater daily operations. EPA has indicated through informal guidance

that if a shutdown is not completed to the point of both no fuel being fired and no steam

or heat being supplied, then a shutdown has not occurred and therefore a startup

cannot occur. This interpretation does not accommodate situations where solid fuel

feed is lost where the feed can be restored before a complete shutdown takes place.

Sometimes wet fuel can cause high O2 conditions, which will trip the ESP, which will trip

the fuel feed. Sometimes there are problems with the equipment used to supply the

solid fuel that cause loss of fuel feed. Companies are incentivized to restart the boiler

as soon as possible and prevent a full shutdown and subsequent startup. Lighting or

re-lighting of a boiler or process heater due to a temporary loss of fuel feed or a “boiler

trip” should be deemed startup and not a malfunction period. This is consistent with

EPA’s approach in the Plywood and Composite Wood Products (PCWP) MACT (40

1 See 80 Fed. Reg. at 3094 (col. 1); see also Assessment of Startup Period at Coal-Fired Electric

Generating Units – Revised, U.S. Environmental Protection Agency, Office of Air and Radiation (November 2014) at 20. 2 EPA’s reliance on the § 112(d) floor setting procedures is particularly misplaced because the 4-hour

period is not even part of the work practice standard – rather, it is one of the criteria that EPA uses to define the period of startup. Thus, even if the floor setting procedures had some applicability under § 112(h), they still would be inapplicable in establishing the criteria that define the startup period.

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CFR 63, Subpart DDDD) to conclude that …. “Lighting or re-lighting any one or all gas

burners in direct-fired softwood veneer dryers shall be deemed startups and not

malfunctions” (See § 63.2250(d)). To address these situations, the shutdown definition

should be modified to say that shutdown ends EITHER (1) when no steam or heat is

being supplied and no fuel is being combusted in the boiler or process heater OR (2)

when startup is initiated by reintroducing fuel to the boiler or process heater after no fuel

has been fed for at least 1 hour, whichever comes first.

The concept of startup being the initiation of fuel after at least 1 hour of no fuel being fed

is consistent with how EPA identified startup periods to do their analysis documented in

the memo “Assessment of startup period at coal-fired electric generating units –

Revised.” The memo states: “For purposes of conducting this analysis, we defined a

startup event as the initiation of fossil fuel combustion following one or more hours of

non-operation (i.e., no combustion), which is consistent with the final definition of startup

in the MATS reconsideration rule.”

B. Startup and Shutdown Work Practices

EPA has proposed several changes to the startup and shutdown work practice

standards in Table 3 of the rule.

1. Clean Fuels

The first change is the expansion of the clean fuels list in the startup work practice in

Table 3, Line 5.b to acknowledge additional clean fuels such as all gaseous fuels

meeting the “other gas 1” classification and fuels that meet the TSM, HCl, and Hg

emission limits using fuel analysis. The requirement that any other clean fuel than

those specifically listed must meet the TSM, HCl, and Hg emission limits for the unit’s

subcategory using fuel analysis is overly restrictive and should not be required for this

work practice. This approach would result in some fuels qualifying for use as clean

fuels in one type of boiler/process heater design but not another, which does not make

sense for a work practice. In addition, not all of a fuel’s TSM, HCl, or Hg content is

emitted out the stack when it is burned. The preamble of the rule (see 80 FR 3095)

indicates in the discussion of the clean fuel revisions that “Sources would demonstrate

compliance either through fuel analysis for the relevant parameters or stack testing.”

There is no mention of demonstrating that a material is a “clean fuel” in the regulatory

language using stack testing (e.g., measuring emissions prior to any controls that would

not be fully engaged during the entire startup period). Such a provision should be

included in the final rule.

2. Dry Biomass is a Clean Fuel

Dry biomass (<20% moisture content) should also be added to the list of clean fuels.

Dry biomass is included in EPA’s definition of “clean cellulosic biomass” and will burn

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cleaner than other solid fuels. It is comparable to paper and cardboard with regard to its

chemical makeup and combustion characteristics. In particular, dry biomass results in

low HCl, Hg, and CO emissions due to its low chloride, mercury, and moisture content,

and PM emissions are estimated to be below the dry biomass subcategory PM limit for

units with mechanical collectors because the AP-42 PM emission factor for a boiler with

a mechanical collector firing dry wood is below the dry biomass subcategory PM limit.

Thus, there is no rational basis for designating paper and cardboard as clean fuels while

excluding dry biomass for units with mechanical PM collectors.

Moreover, as explained above, we believe that EPA is not as constrained in setting

work practice standards under § 112(h) as the Agency appears to believe. The

apparent goal of requiring clean fuels to be combusted during startup is to minimize

HAP emissions during the period during which air pollution controls are not operating or

not operating at full efficiency.3 We believe that burning dry biomass during startup

represents a best practice for minimizing HAP emissions during startup for industrial

boilers with mechanical PM collectors and, thus, should qualify as an appropriate work

practice even under EPA’s more constrained view of the law. In any event, EPA has a

rational basis for designating dry biomass as a clean fuel for units with mechanical PM

collectors because, as explained above, emissions attributable to the combustion of dry

biomass in such units should generally be expected to meet HAP emissions limitations

for dry biomass boilers, even during startup periods. Therefore we request EPA add dry

biomass to the list of clean fuels for the startup/shutdown work practices for all solid fuel

boiler types.

3. Startup Clarification Needed

Another useful clarification that we ask EPA to make, for boiler/process heater designs

that start using a bed of material where ignition of the fuel is accomplished using clean

fuels, is to change “start firing” to “start feeding.” This clarification is similar to that EPA

proposes to make in the shutdown definition to accommodate units of this design.

4. Time to Engage PM Controls

In conjunction with the proposed alternative definition of startup, EPA also proposes to

require that PM controls be engaged within only 1 hour of first firing fuels that are not

clean fuels. We provided extensive comments in the prior Boiler MACT reconsideration

proceeding that certain operating conditions must be reached before engaging ESPs to

control PM emissions and incorporate those comments by reference. Some of the

operating conditions were also discussed in the previous section. Premature starting of

ESPs will lead to short-term stability problems that could result in unsafe actions and

3 See, e.g., 78 Fed. Reg. at 7147 (“[T]he HAP emission reduction benefits warrant additional utilization of

such fuels until the temperature and stack emissions pressure is sufficient to engage the APCD.”).

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longer term degradation of ESP performance due to fouling, increased chances of wire

damage, or increased corrosion within the chambers. Vendors providing this equipment

incorporate these safety and operational concerns into their standard operating

procedures. EPA notes in the preamble at 80 FR 3094 that “The EPA agrees with the

petitioners that the startup period should not end until such time that all control devices

have reached stable conditions.” Attachment 1 contains an excerpt from an ESP

operating manual that illustrates this point.

During periods of startup, combustion begins as fuel is introduced into the boiler and the

boiler and ESP warm up on a designated curve that could last for several hours. As the

control device is heated up, additional fuel is added until the ESP (and other equipment)

meets its design temperature and normal fuel firing is at steady state. Attachment 2

contains an excerpt from the operating manual of an ESP recently installed at a wood

products facility. The manufacturer states that warming should occur at increments of

200F per hour and the ESP should not be engaged until two hours after the stack gas

temperature has reached 300F. This shows that 1 hour is not sufficient time to reach

safe conditions that will allow facilities to engage ESPs .

One member company employs the following safety procedures when starting up

boilers:

Purging of the boiler – prior to startup or lighting the fire, completely purge the

system with ambient air for a few minutes at the rate of approximately one-fourth

the requirements for maximum capacity of the unit.

Heating rate – Boiler temperature should increase at 100F per hour. This

prevents exceeding the safe limits for pressure part protection and superheater

tube metal temperatures. It is also a safe practical limit on drum stress to protect

rolled tube joints against leakage.

Some ESPs have oxygen sensors and alarms that shut down the ESP at high flue gas

oxygen levels to avoid a fire in the unit. The oxygen level is typically high during

startup, so the ESP may not engage due to these safety controls until more stable

operating conditions are reached. The literature and fire codes like NFPA 85 - Boiler

and Combustion Systems Hazards Code and NFPA 86 - Standard for Ovens and

Furnaces, recommend maintaining the concentrations of carbon monoxide below 2%

and oxygen below 6-8% to minimize the potential for fires and explosions downstream

of the firebox and especially in the dry ESP. These values are considered trip points in

the design and operation of ESPs. When the trip point is triggered, ESP power is

turned off to eliminate the potential of sparking in the dry ESP providing a source of

ignition. De-energizing the T-R causes the ESP voltage to drop to zero, thus eliminating

the potential for the spark point. These are safety measures that not only are

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recommended by the ESP manufacturers but are also industry’s standard practices and

hence incorporated into companies’ risk management plans and policies.

Some boilers/process heaters do not currently have the capability to fire gas and are not

located in an area where natural gas is available. EPA has acknowledged the fact that

not all boilers are designed to burn gas or distillate oil by establishing multiple design-

based subcategories. In the previous reconsideration effort, EPA requested comment

on whether sources should be required to use specific fuels during periods of startup

and shutdown. The Agency determined when promulgating the January 2013 rule that

it was not appropriate to require industrial facilities to utilize the maximum amount of

clean fuel during startup (this requirement is included for EGU’s in the MATS rule but

not in the industrial boiler rules).

We continue to strongly support EPA’s conclusion in the preamble to the June 2010

proposed rule that fuel switching is not an appropriate control option to mandate. See

75 FR 32019. Many facilities with biomass boilers are located in rural areas that lack

the necessary gas infrastructure. More generally, gas supplies are limited and industrial

users are of lower priority than residential users during times of supply shortfalls and

cold weather. Industrial boilers competing with utility boilers for gas supplies and

increasing electricity demand in the coming years, coupled with increasing reliance on

natural gas to meet that demand, will place further strain on limited gas supplies and

distribution networks.

Many units that start up on biomass use listed clean fuels to ignite a bed of biomass, but

1 hour is not sufficient time after commencement of additional biomass feeding for the

appropriate stack temperature and oxygen conditions to be reached to engage an ESP.

It is not cost effective, and on balance has no environmental benefit, for these units to

install gas burners and the required infrastructure to burn gas when startups may only

occur once or just a few times per year. Some facilities, such as forest products

facilities, burn biomass in their boilers/process heaters as an integral part of their

production process.

It would be unreasonable and arbitrary for EPA to require engaging ESPs within 1 hour

of firing certain fuels if this practice is not safe and the ESP cannot be properly

operational within an hour. It takes time to reach stable operation when transitioning

from startup fuel to solid fuels. The footnote (a) included in the proposed startup

alternate work practice – which allows for EPA to approve case-by-case alternatives – is

not adequate to address this concern. It would be difficult for all facilities to compile the

information that will allow the permitting authority or regional EPA office to make a

timely decision on whether to grant a variance to the 1 hour requirement. Facilities are

configuring their compliance systems for monitoring and recordkeeping now. Waiting

for these provisions to be finalized, developing a petition, and then waiting for approval

12

of that petition will not provide a clear compliance path before the January 31, 2016

compliance date.4 If the petition process to request a variance from this requirement is

retained in the final rule instead of including ESPs in the list of controls that must be

engaged as soon as is practical, EPA must clarify the procedure and timing on the

process to give facilities a clear path for compliance. In order for the process to be

feasible prior to the compliance date, EPA should grant authority to permitting agencies

with Title V delegated authority to review and approve these variance requests in

63.7570 and should not rely on the burdensome process for approval of alternate work

practice standards in 63.6(g). EPA already allows states with approved Title V

programs to grant compliance extensions for Part 63 rules (see 40 CFR 63.6(i)(4)(i)). In

addition, the variance should be considered to be approved if no action is taken by the

agency within 30 days of a complete submittal.

There is no mention of how much additional time a facility can receive as a result of the

petition. Facilities should be able to develop their own procedures to ensure safe

engagement of ESPs at the appropriate time (e.g., a certain stack temperature instead

of a certain amount of time). In addition, the requirement to demonstrate that the ESP

is appropriately sized to meet the PM limit does not acknowledge that there may be

another control device that has been installed other than ESP that provides additional

PM control (e.g., scrubber). Lastly, the phrase “violates manufacturer’s recommended

operation and/or safety requirements” in footnote a of Table 3 should be replaced with

“is inconsistent with manufacturer’s recommended operation and/or safety

requirements.”

It is not clear to us why EPA is treating startup timing of PM control equipment

differently under the 2 sets of startup definitions and work practices. EPA has already

acknowledged that certain types of controls have temperature limitations. The response

to comments document that supports the changes to the January 31, 2013 final rule

states:

“The EPA carefully considered fuels and potential operational constraints of air pollution control devices when designing its work practices for periods of startup and shutdown. The EPA is aware that SNCR and SCR systems with ammonia injection need to be operated within a prescribed and relatively narrow

4 In addition, neither the footnote to Table 3 nor the preamble discussion of the footnote clearly explain

the mechanism by which a request for an alternative would be approved. Since the 1-hour startup requirement for PM controls is written into the rule at Table 3, EPA presumably would not be able to revise that regulatory requirement for a particular source without undertaking further rulemaking. If that is EPA’s intention, the time required for such facility-specific rulemaking would cause this approach to be unworkable in the short time between publication of the final reconsideration rule and the compliance deadline for existing sources. On the other hand, if it is EPA’s intent to approve facility-specific alternatives without conducting rulemaking, this approach would be unlawful because EPA can revise a legislative rule only through further rulemaking. For this reason alone, it is imperative for EPA to write into the final rule an appropriate alternative to the proposed 1-hour requirement.

13

temperature window to provide NOx reductions. Further, the EPA is aware that dry scrubbers also need to be operated close to flue gas saturation temperature, and that fabric filters need to be operated at temperatures above the acid dew point. Because these devices have specific temperature requirements for proper operation, the EPA notes in its work practices that it is the responsibility of the operators of affected boilers and process heaters to start their SNCR, SCR, fabric filter, and dry scrubber systems appropriately to comply with relevant standards applicable during normal operation.”

As the information provided above indicates, ESPs have the same type of temperature

constraints as EPA acknowledges above. In addition, many ESPs also have oxygen

concentration restrictions in order to prevent fires in the units. As such, ESPs should be

added to the list of control devices to be started as expeditiously as possible in the first

startup work practice. In the second startup work practice, EPA should not set an

arbitrary 1 hour startup requirement for PM controls on industrial boilers and process

heaters with no information to support such a requirement. The preamble at 80 FR

3094 states that “The EPA agrees with the petitioners that the startup period should not

end until such time that all control devices have reached stable conditions.” For many

facilities, the proposed requirement in the second startup work practice to start PM

controls (including fabric filters) within 1 hour of first firing solid fuel is in conflict with

EPA’s justification for the first work practice and EPA’s statement in the preamble.

C. Startup and Common Stacks

Some facilities with two or more boilers in the same subcategory route the boiler

exhausts through a common stack with common monitoring systems including CEMS

and COMS. These boilers may or may not utilize common air pollution control

technology. The boilers’ operating schedules (including startups, shutdowns, and

maintenance outages) often do not coincide due to numerous operational and

maintenance-related factors. It is not clear in the reconsideration proposal how these

provisions would be applied to multiple boiler/common stack/common CMS scenarios.

Regardless of whether an individual boiler exhausts through an individual or common

stack, fuel combustion and control device operational issues associated with startup

and shutdown events will be the same. Since the boilers themselves operate

independently, each will be subject to the same sequence and duration of startup and

shutdown-related operational stresses regardless of the operational status of the other

boiler(s) exhausting through the common stack. While the exhaust from other common

stack boilers operating outside of startup or shutdown conditions may serve to dilute the

impact of an individual boiler operating in startup/shutdown mode, startup/shutdown

emissions will inevitably serve to inflate emissions measured by the common CMS

unless the startup/shutdown definitions and work practices are applied on an individual

boiler basis. We request that EPA clarify that, in situations where multiple boilers

14

discharge through common stacks (with or without common CMSs), the

startup/shutdown provisions should be applied as if each boiler were served by an

individual stack and CMS. Documentation of these events for a common system will be

no more difficult than for fully independent boilers. While the data from the common

CMSs may have to be flagged for multiple startup/shutdown events as individual boilers

come on and go off line, no more flagged startup/shutdown time will be excluded from

the calculated 30-day rolling averages than would have been allowed on an individual

stack basis. This treatment will, however, avoid the logging of apparent deviations which

should have been obviated by proper application of the startup/shutdown provisions.

It should also be clarified that compliance testing of the common stack should not be

performed when any of the boilers feeding the common stack are in startup or

shutdown.

D. Additional Monitoring and Recordkeeping During Startup and Shutdown

EPA has proposed substantial additional startup and shutdown monitoring and

recordkeeping requirements, including a new startup and shutdown plan. (Based on the

preamble language, we believe it may have been EPA’s intent to impose the

requirement for the startup and shutdown plan only on facilities using the second

definition of startup, but the proposed rule does not make this clear.) The first definition

of startup, as previously mentioned, is not workable in many situations. Therefore,

many facilities will be relying on the alternate definition and work practice in order to

have a better assurance of compliance with the startup requirements. However, in

attempting to address our concerns and provide more achievable startup requirements,

EPA has also added significant burden and made the recordkeeping requirements in

this rule even more complicated to implement.

The additional monitoring and recordkeeping burden does not provide any additional

environmental benefit. Overly prescriptive and non-facility-specific requirements can

actually be counterproductive, restricting the operators’ flexibility in a way that hampers

their ability to troubleshoot or respond to an event, or that compromises safety.

Facilities currently have tools like checklists that operators use to ensure proper startup

and shutdown procedures are followed. The particular parameters that define when

useful thermal energy is supplied will be unit-specific and will be identified in the startup

and shutdown plan. EPA should simply require a certification that facilities followed the

established procedures (either those in the rule or those in a startup and shutdown plan)

and records of the time when each startup and shutdown began and ended.

The hourly records of control device and other parameters EPA proposes to require at

63.7555(d)(11) and (12) do not provide any value or serve to reduce emissions, but only

add regulatory burden to an already burdensome rule. Stack temperature will not be

15

useful for sources with wet stacks and scrubber liquid to gas ratio and differential

pressure of the liquid during startup will not be meaningful because stack gas flow will

be low and scrubber pressure drop is already monitored. EPA should either pare back

the list of required records to only those that specifically and directly relate to

demonstrating compliance with the work practice, or provide them as a list of possible

(but not limited to) items a facility may utilize to demonstrate compliance with the work

practice relevant to their circumstances.

Lastly, although it may have been EPA’s intention to only require the additional

requirements when using the alternate approach, the rule language reads as though

these are new requirements no matter what definition of startup is utilized. If EPA

decides to impose additional requirements (which it should not for the reasons

explained above), EPA should make it clear in the final rule that the new requirements

proposed at 63.7555(d)(11) and (12) apply only if startup definition 2 is selected. This

intent was stated in the preamble at 80 FR 3094.

III. Malfunctions and Affirmative Defense

A. Elimination of Affirmative Defense for Malfunctions

EPA proposes to delete a provision that accords boiler/process heater operators an

affirmative defense to civil penalties for excess emissions associated with malfunction

events, provided the malfunction meets certain criteria and the operator complies with

reporting requirements. EPA explains that this proposed deletion is based on a

decision of the U.S. Court of Appeals for the District of Columbia Circuit, NRDC v. EPA,

749 F.3d 1055 (2014), which held that EPA lacks authority to promulgate such a

provision, because the CAA gives the district courts the power to determine appropriate

penalties in a civil judicial enforcement action, not EPA. EPA does not discuss,

however, and it appears not to have even considered, whether the boiler/process heater

emission standards are appropriate (i.e., are consistent with congressional directives) in

the absence of an affirmative defense for malfunctions.

Simply eliminating the affirmative defense provision without assessing the need for

some other adjustment in the boiler/process heater emission standards in light of that

change does not comply with the CAA. The affirmative defense was something that

EPA considered necessary when EPA promulgated the current standards, and it was

part of the statement of basis and purpose for the standards that EPA was required to

publish under CAA § 307(d)(6)(A). The preamble to the proposal to eliminate the

affirmative defense does not explain at all why the remainder of the standards do not

need to be changed in light of that elimination. EPA cannot simply delete a critical piece

of a rule without at least analyzing and explaining to the public why the rule still is

appropriate and consistent with statutory requirements in the absence of that critical

16

piece. Thus, EPA must publish a new or supplemental statement of basis and purpose

for the proposed rule that explains and allows for public comment on the

appropriateness of applying the boiler/process heater emission standards to malfunction

periods without an affirmative defense provision. (As explained briefly in the following

subsections of these comments, we do not believe that EPA can lawfully promulgate the

boiler/process heater emission standards in the absence of an affirmative defense

provision without making some other adjustments to the standards. That discussion,

however, is one that properly occurs after EPA has published, and solicited public

comment on, EPA’s explanation of why promulgating the boiler/process heater emission

standards with no affirmative defense for malfunctions and without considering the

effect of malfunctions when setting the standards is legally permissible and

appropriate.)

Although the preamble fails to provide any direct explanation of why EPA can just

eliminate a portion of the regulations without discussing or even considering the

appropriateness of the remaining requirements, EPA seems to imply that the affirmative

defense was not really a necessary part of the standards but was nevertheless included

in the standards “to provide a more formalized approach and more regulatory clarity.”

See 80 FR 3101. This statement does not excuse EPA’s failure to reconsider its

statement of basis and purpose for the boiler/process heater emission standards with

the affirmative defense for malfunctions removed.

In the first place, the affirmative defense was a key element of EPA’s explanation for

why it was lawful for the Agency to promulgate MACT standards that apply during

malfunctions but that do not reflect what is achievable with available technology during

malfunctions. See 76 FR 15613. Obviously, the Agency believed at the time that an

affirmative defense provision was necessary to effectuate the congressional directive

that MACT standards be based on what is achievable with available technology;

otherwise, EPA would have had no statutory authority to promulgate the affirmative

defense.

Moreover, the administrative record clearly indicates that EPA considered the effect of

the affirmative defense when it decided where to set the emission standards for boilers

and process heaters. For example, in the Response to Comments document for the

current standards, EPA stated: “EPA agrees with the commenter that the malfunction

periods do not qualify for affirmative defense and should be factored into the MACT

floor calculation since these flagged ‘malfunctions’ occur too often. We revised the

analysis of the CO CEMS data to include the flagged malfunction periods. The final rule

contains the revised emission limits.” EPA-HQ-OAR-2002-0058-3846 p. 259. See also

EPA-HQ-OAR-2002-0058-3877 p. 11 (“CO CEMS data from periods of malfunction

were included in the analysis. This change was due to the fact that when facilities

comply with the amended final Boiler MACT frequent periods of malfunction cannot

17

qualify for the Affirmative Defense provisions in the amended final rule and these data

will need to be included in the rolling averages. It would thus not be appropriate to

exclude them from the calculations.” (emphasis added)). In other words, whether or not

excess emissions associated with unavoidable equipment failures would qualify for the

affirmative defense (which requires that the events be infrequent, see 40 CFR

§ 63.7501(a)(1)(i)) dictated whether EPA would factor those emissions into setting the

standard, or would rely instead on the affirmative defense to address those emissions.

Having taken the affirmative defense into account when deciding what emission

standards are appropriate, EPA cannot now eliminate the affirmative defense without

reassessing the appropriateness of those emission standards as applied to malfunction

periods and how they will affect boiler/process heater operators if the standards are no

longer mitigated by the affirmative defense. EPA must then publish its analysis and

seek public comment on it before promulgating a final rule that removes the affirmative

defense provision.

B. EPA Is Required To Take Malfunctions into Account when Setting MACT Standards

As noted above, how EPA should establish MACT standards, pursuant to the

congressional mandates that those standards must be achievable with available

technology, and that they must be at least as stringent as the actual emissions of the

best performers, in light of the inevitability of some malfunctions that will cause

increased emissions, is an issue that should be debated in the public comment period

once EPA has stated its position with respect to issuing MACT standards that apply

during malfunctions but without an affirmative defense provision. The January 21, 2015

proposal lacked any analysis of this issue and does not satisfy the requirements of CAA

§ 307(c) with respect to promulgating MACT emission standards for boilers and process

heaters without an affirmative defense provision. Nonetheless, we will address briefly

here EPA’s obligation to take malfunctions into account when establishing MACT

standards. Many of the undersigned organizations commented on that issue during the

rulemaking establishing the current boiler/process heater emission standards, and those

comments are incorporated herein by reference.

The court decision that EPA cites as the reason for eliminating the affirmative defense

provisions of the current standards said nothing about (a) whether EPA must consider

the effect of malfunctions when it sets emission standards that apply at all times (except

during some startup and shutdown periods); or (b) whether it is appropriate for the

MACT standards to contain an alternative emission standard that applies during

malfunction events that meet certain criteria. The only basis for the court striking down

the affirmative defense in that case was that it dictated to the federal district courts

whether a civil penalty was appropriate for a particular violation, whereas the statute

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gives the authority to determine an appropriate penalty for a violation to the court. See

749 F.3d at 1063-64. Because the affirmative defense in the Portland Cement MACT

standards at issue in that case, as with the affirmative defense provision in the current

boiler/process heater emission standards, applied after a violation occurred, rather than

being part of how a violation is determined, the affirmative defense intruded into the sole

discretion of the district courts. Thus, while the court decision is grounds for EPA

eliminating the affirmative defense as written, it in no way authorizes EPA to remove the

affirmative defense from the boiler/process heater emission standards without

substituting some other provision addressing malfunctions, nor does it allow EPA to

remove the affirmative defense without even considering whether/how the remainder of

the emission standards must be revised in light of the removal of the affirmative

defense.

The statutory language is clear: Section 112(d) requires EPA to create standards that

are achievable based on identified emission reduction measures or the demonstrated

emission performance of existing sources, and to limit emissions only “where

achievable.” Section 112(d)(3) requires the standards at minimum to reflect actual

achievements in the field by best performers. For new sources, § 112(d)(3) sets this

“floor” for what is “achievable” as “the emissions control that is achieved in practice by

the best controlled similar source” (emphasis added). For existing sources, it requires

that the MACT standard reflect at least the average level of control “achieved” by the

top class of best-performing existing sources. In both cases, where, as here, EPA

bases MACT standards on the “floor,” § 112(d) thus requires EPA to ground its

decisions on actual performance. When EPA ignores emissions that even best-

performing sources experience during malfunctions, EPA breaches its duty to set

standards on the basis of real-world performance. It fails to take into account how

sources actually operate and unlawfully prohibits emissions that cannot be avoided.

See, e.g., Sierra Club v. EPA, 167 F.3d 658, 665 (D.C. Cir. 1999) (best-performing

source should not violate a standard supposed to be based on what it “achieve[s] in

practice”); see also 76 FR 15628 (rejecting a comment as “inappropriate” because it

“would result in emission limits that even the best performing sources would be

expected to exceed”). EPA's position--that the statute requires it to set section 112-

compliant emission standards that apply at all times, but that EPA can meet this

mandate by setting emission standards based on what is achieved and achievable only

part of the time--simply makes no sense.

Every court that has addressed the issue, both under the CAA § 111 requirement that

standards be based on the best demonstrated control technology and under the similar

technology-based requirements of CAA § 112(d) and (h), has indicated that EPA must

take the effect of malfunctions on emissions into account when establishing such

technology-based emission standards. See Portland Cement Ass’n v. Ruckelshaus,

19

486 F.2d 375, 398-99 (D.C. Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d

427, 432 (D.C. Cir. 1973); Nat’l Lime Ass’n v. EPA, 627 F. 2d 416, 431 (D.C. Cir. 1980);

Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855, 872 (D.C. Cir. 2001); Nat’l Ass’n

of Clean Water Agencies v. EPA, 734 F.3d 1115, 1158 (D.C. Cir. 2013).

EPA may be implying that the “flexibility” EPA has to consider the effect of a malfunction

on the ability of the source to comply in determining an appropriate enforcement

response, and the opportunity that a source would have to argue to a court in an

enforcement action that a malfunction justifies a reduced or no penalty, is a satisfactory

means of accommodating the effect of malfunctions on what standards are achievable

with available technology. See 80 FR 3101. But the statute directs EPA to set

standards based on what the available technology can do or, in the case of MACT floor

standards, based on what the best performers are actually doing. Nothing in the

statutory language or legislative history indicates that Congress intended EPA to

establish MACT standards that apply at all times, but that even best performers cannot

meet during unavoidable malfunctions, and then have penalties potentially mitigated in

an enforcement action.

The courts agree with this analysis, stating repeatedly that relying on enforcement

discretion is no substitute for setting technology-based standards that reflect the

performance of that technology during all reasonably anticipated conditions (such as

malfunctions, which EPA expects will occur, see 76 FR 15613). See, e.g., Portland

Cement, 486 F.2d at 398 n.91; Nat’l Lime, 627 F. 2d at 431 n.46; Marathon Oil Co. v.

EPA, 564 F.2d 1253, 1273 (9th Cir. 1977). Moreover, the enforcement discretion

approach does not satisfy the purpose of CAA § 112 — reducing HAP emissions. A

post-hoc case-by-case evaluation of emission circumstances, as EPA intends to handle

all malfunction periods, will not prevent or reduce emissions of HAP. And rather than

the starting point being affirmative steps to prevent emissions as Congress intended,

the starting point of EPA’s proposed approach is the post-emission presumption of

wrongdoing by the source operator.

C. Tools for Accounting for Malfunctions in the Standards Once the Affirmative Defense Is Eliminated

Considering the effects of malfunctions on boiler/process heater emissions and writing

the applicable MACT standards to take those effects into account is not only something

that the Clean Air Act requires EPA to do, but it also is something that EPA has the

technical and legal capability to do. Just as it has done with emissions during startup

and shutdown, EPA can address emissions during malfunctions with work practice

standards. There also may be some types of malfunctions for which EPA can analyze

available data or collect additional data to support promulgation of alternative numerical

emission limitations.

20

EPA can address malfunctions using the authority Congress gave it in CAA §§ 112(h)

and 302(k) to substitute a design, equipment, work practice, or operational standard for

a numerical emission limitation. The use of such “work practices” will in most cases be

more practicable and more comprehensive than trying to establish numerical standards

to address all malfunctions. Given the wide range of events that meet EPA’s definition

of “malfunction” and can result in excess emissions, and given that by definition the

source cannot reasonably be designed or operated to avoid malfunctions, it is eminently

reasonable to address malfunctions through requirements that the source take all

reasonably available measures to reduce the frequency, magnitude, and duration of the

malfunction. One approach that has proven effective in the past is to specify the

elements and objectives of a plan that the source must develop, follow, and review to

assure that the source is taking the appropriate steps before, during, and after a

malfunction to minimize excess emissions. Indeed, EPA would no doubt find that most

if not all or the sources identified as “best performers” have such plans and follow them

to responsibly address malfunctions. Prior public comments on the boiler and process

heater emission standards have offered numerous examples of how a work practice

standard can function effectively to minimize emissions consistent with the capability of

available technology.

EPA has already shown that it can use work practices to address the effect on

emissions when a source is operating in other than normal steady-state operation, when

EPA established work practice standards in lieu of numerical emission limitations for

boilers and process heaters undergoing startup or shutdown. See 76 FR 15642. EPA

correctly determined that conditions during startup and shutdown are not amenable to

monitoring compliance with a numerical standard, and that is true even more so with

respect to malfunctions. In fact, EPA regulations long have specified that malfunctions

are not representative conditions for purposes of monitoring emissions and determining

compliance. See 40 CFR §§ 60.8(c) and 63.7(e)(1). Because malfunctions are not

planned events, it is not practicable, and in the vast majority of cases not possible, to

arrange for, set up, and conduct stack testing to measure emissions during

malfunctions, for purposes of deriving numerical emission limits or determining

compliance with such limits. Continuous monitoring data may be available to

characterize certain types of malfunctions, but for many malfunctions the unpredictable

timing and stack conditions make even the accurate measurement of emissions with

CEMS impracticable. Continuous monitors must be operating within a specified range

to provide accurate data, and they also typically have to be calibrated for the specific

stack conditions. Malfunctions therefore can result in conditions that make CEMS

inaccurate. Thus, addressing malfunctions in the development of § 112 standards is the

type of situation that Congress provided for with the work practice authority it gave EPA

in CAA § 112(h).

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In addition to using its work practice standard authority, EPA may also, if available data

support them, promulgate alternative numerical emission limitations that apply during

some types of malfunctions. As noted in the above quotation from the Response to

Comments for the current boiler/process heater emission standards, in some cases

EPA already has data on emissions during malfunctions that might allow EPA to

establish a numerical emission limitation under CAA § 112(d) that reflects emissions

that best performers experience during certain types of malfunctions. EPA generally

asked sources not to submit such data when EPA was developing the standards, or

directed that emissions during malfunction events not be included in averages, but there

is a substantial amount of continuous monitoring data available that includes the effect

of malfunctions, should EPA choose to analyze it. See, e.g., EPA-HQ-OAR-2002-0058-

3265, "Revised Development of Baseline Emission Factors for Boilers and Process

Heaters at Commercial, Industrial, and Institutional Facilities,” p. 20 (“if emission

monitoring data was reported during periods of start-up, shutdown, or malfunction,

these data were excluded from the analysis"); EPA-HQ-OAR-2002-0058-3877 p. 10

(owners were told to exclude emissions data from malfunctions from ICR Phase I

submissions).

Moreover, there are many years’ worth of data on the cause, frequency, duration, and

magnitude of emissions during malfunctions that many boiler operators must submit

semiannually because they are subject to Subpart D – Dc NSPS. See 40 CFR §

60.7(b)-(d). EPA could collect and analyze those data to determine what effect

malfunctions have on emissions from well-designed and well-operated units, and EPA

might then be able to use that information to derive alternative numerical limitations that

apply during malfunctions or to determine an appropriate procedure and averaging

period for determining compliance with emission limitations that apply during normal

operations, in light of the likelihood of malfunctions. Also, for certain types of

malfunctions, EPA may already have the data, or it may be able to obtain the data from

existing sources or from equipment vendors, to assess the effect on emissions from that

type of malfunction and establish an alternative numerical limitation based on those

data. 5

5 Previous standard-setting for boilers also demonstrates the implausibility of EPA’s claim here that it

would be infeasible for EPA to account for malfunctions when establishing emission standards under CAA § 112. A September 14, 1995 letter to Richard Everhart of the Air Pollution Control District of Jefferson County, Kentucky from Jewell Harper, Chief of the Air Enforcement Branch at EPA Region IV, available from EPA’s Applicability Determination Index, Control No. 9600119, citing statements in the Federal Register preamble for the final Subpart Db NSPS, responds to an inquiry about why the 40 CFR Subpart Da NSPS (for Electric Utility Steam Generating Units) differ from the Subpart Db NSPS (for Industrial-Commercial-Institutional Steam Generating Units) in their treatment of emissions during startup, shutdown, and malfunction (SSM). The letter explains that the Subpart Db standards require SO2 emissions during SSM periods to be included in calculating 30-day rolling average emission rates for determining compliance, while the Subpart Da standards do not, because “the Agency believes that typical Subpart Db boilers are considerably smaller than Subpart Da boilers, and that due to their smaller

22

Before EPA removes the affirmative defense from the boiler and process heater

emission standards, EPA should determine an appropriate set of work practices, or a

combination of work practices and alternative numerical emission limitations if EPA

determines the latter are feasible to address certain malfunctions, that address higher

emissions associated with malfunctions of properly designed and operated MACT

technology. Of course, whether the alternative standards are reasonable and supported

by available information is something that affected boiler/process heater operators will

need to assess and comment on, so EPA must first offer its analysis for public comment

before finalizing the deletion of the affirmative defense and the adoption of the

alternative standards. (EPA should proceed to final action on the remainder of the

changes discussed in the January 21, 2015 notice and in these comments while it

reconsiders the affirmative defense/malfunction issue as described above.)

IV. PM CPMS Requirements

A. An Exceedance of an Operating Parameter Should not be a Presumptive Violation of the Standard

The January 2013 amended final rule requires units combusting solid fossil fuel or

heavy liquid with heat input capacities of 250 MMBtu/hr or greater to install, maintain,

and operate PM CPMS. These sources establish a site-specific enforceable operating

limit in terms of the PM CPMS output during the initial and periodic performance tests,

and meet that operating limit on a 30-day rolling average basis. Sources are allowed a

certain number of exceedances of the operating parameter limit before an exceedance

would be presumed to be a violation, and certain low emitting sources are allowed to

‘‘scale’’ their site-specific operating limit to 75 percent of the emission standard.

An operating parameter excursion should not be a presumptive violation of the

standard. No other operating parameter is treated in this manner and a non-certified

PM CPMS should not be treated as such. A higher reading from a PM CPMS is an

indication that the characteristics of the PM in the stack gas are different from the stack

test conditions, not necessarily that a violation has occurred.

As currently structured under §63.7540(a)(18), any deviation from the established PM

CPMS 30-day average operating limit sets in motion a sequence of very onerous

requirements. Within 48 hours the source must do an inspection of the air pollution

size Subpart Db boilers can comply with SO2 limits by burning natural gas or low sulfur oil during flue gas desulfurization (FGD) system malfunction. The preamble for Subpart Db also indicates that, due to improvements in FGD technology since the promulgation of Subpart Da, it is not necessary for the emission standards in Subpart Db to mimic those in Subpart Da.” Without necessarily endorsing the outcome in that instance, it demonstrates that EPA can apply that kind of qualitative analysis of available information on processes and control technologies, leading to adjustments in the numerical limitations that apply during malfunctions.

23

control device (APCD) and within 30 days of the deviation the source must conduct a

PM emissions compliance test (notwithstanding that §63.7(b) requires 60 days’ notice of

such a test). Both actions are required despite the fact that the deviation may not imply

an emission deviation at all and that the required inspection may not have indicated any

APCD-related issues. Further, under §63.7540(a)(18)(iii), more than 4 PM CPMS

deviations requiring stack tests in a 12-month operating period is regarded as a

separate violation of the subpart even if no actual emissions violation has been

documented. Given that the reliability of PM CPMS has not been established for all

types of sources, these provisions seem excessively punitive and burdensome in

comparison with the traditional treatment of deviations from other CPMS operating

limits. We believe that the rule should be amended to provide for reporting of any PM

CPMS 30-day average operating limit deviation in the appropriate semiannual report

along with any needed corrective actions, as would be required for any other CPMS

deviation. If the Administrator deems the number of deviations to be excessive, taking

into account PM CPMS reliability, the specific circumstances surrounding the

deviations, and the corrective actions taken, the Administrator has the discretion to

require a stack test or take any other appropriate measure.

B. Certification of PM CPMS

We agree with EPA’s proposal to remove the requirement to “certify” particulate matter

(PM) continuous monitors used as parametric (CPMS) rather than direct emissions

compliance monitors (CEMS) for PM emissions. As Performance Specification 11 is

applicable only to use of a PM CEMS, we were very unclear how a certification would

be conducted for a PM CPMS. Therefore, it is appropriate to remove the requirement to

“certify” in 63.7525 because there is no procedure to certify a monitor used as a CPMS.

V. Minimum CO Limits

In the January 31, 2013 final Boiler MACT rule, EPA established minimum thresholds

for CO limits in an acknowledgement that below a certain CO level, HAP emissions do

not continue to decrease (because HAP combustion is essentially complete) as CO

emissions decrease. We support the minimum CO limits of 130 ppm that EPA

established in the 2013 final rule.

EPA has justifiably used a CO standard as a proxy for organic destruction for over

20 years. It is well established that CO is harder to combust than the volatile HAPs that

might be emitted by industrial boilers and other similar combustion sources. In this

respect, CO actually is a conservative surrogate for volatile HAPs from industrial boilers

because CO is the last compound to be oxidized. In testing of coal-fired boilers

conducted in support of the Utility MACT, EPA found that “organic compounds tend[ed]

to be at or below the MDL in coal combustion flue gas samples” even when CO was

measured in the flue gas at levels of 23 to 137 ppm. See 76 FR 24976, 25039.

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Decreasing levels of CO are correlated with increasing destruction of organic

compounds until a threshold is reached where, because combustion of CO is the last

step in combustion, the combustion of organic materials is essentially complete. See

78 FR 7144-45. Therefore, EPA was correct to establish 130 ppm at 3% O2 as a

minimum CO standard.

EPA notes in the proposal that, “At levels lower than 150 ppm, the mean levels of

formaldehyde appear to increase.” For unknown reasons, EPA failed to include

language that was included in the last Boiler MACT reconsideration rule that, “we are

aware of no reason why CO concentrations would continue to decrease and

formaldehyde concentrations would increase as combustion conditions improve.” 78

Fed. Reg. 7138, 7145 (Jan. 31, 2013). The Agency concluded that the formaldehyde

emissions data likely were skewed higher at low concentrations due to “imprecise

formaldehyde measurement at low concentrations (i.e., 1-2 ppm).” Id. Those

observations and conclusions are equally valid and applicable here.

The first EPA regulation to set a carbon monoxide (CO) standard for combustion was

the “Burning of Hazardous Waste in Boilers and Industrial Furnaces” (56 Fed. Reg.

7134, February 21, 1991) under the Resource Conservation and Recovery Act (RCRA).

In that rule EPA set a CO standard of 100 ppmv. EPA chose that limit because their

research indicated that while CO was a good surrogate for the destruction of organics,

the validity of that surrogacy broke down at CO levels of approximately 400 ppmv

because the combustion of organics was essentially complete. Based on EPA’s

authority under RCRA to establish standards that are protective of human health and

the environment, the Agency established a 100 pmmv standard as protective.

The Agency later justifies a 100 ppmv standard at 70 Fed. Reg. 59462 (October 12,

2005) for the hazardous waste combustion NESHAP:

“We explained at proposal why the carbon monoxide standard of 100 ppmv and the hydrocarbon standard of 10 ppmv are appropriate floors. See 69 Fed. Reg. at 21282. The floor level for carbon monoxide of 100 ppmv is a currently enforceable Federal standard. Although some sources are achieving carbon monoxide levels below 100 ppmv, it is not appropriate to establish a lower floor level because carbon monoxide is a conservative surrogate for organic HAP. Organic HAP emissions may or may not be substantial at carbon monoxide levels greater than 100 ppmv, and are extremely low when sources operate under the good combustion conditions required to achieve carbon monoxide levels in the range of zero to 100 ppmv. (See also the discussion below regarding the progression of hydrocarbon oxidation to carbon dioxide and water). As such, lowering the carbon monoxide floor below 100 ppmv may not provide significant reductions in organic HAP emissions. Moreover, it would be inappropriate to establish the floor blindly using a mathematical approach—the average

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emissions for the best performing sources—because the best performing sources may not be able to replicate their emission levels (and other sources may not be able to duplicate those emission levels) using the exact types of good combustion practices they used during the compliance test documented in our data base. This is because there are myriad factors that affect combustion efficiency and, subsequently, carbon monoxide emissions. Extremely low carbon monoxide emissions cannot be assured by controlling only one or two operating parameters.”

Thus, while it is certainly possible to reliably measure CO to levels well below 100 ppm,

EPA is justified in setting the Industrial Boiler MACT CO limits for fossil fuel-fired units at

130 ppm at 3% oxygen (which is equivalent to 100 ppm at 7% oxygen) because, below

that level, a further lowering of CO should not be expected to translate to a

corresponding reduction in HAP emissions. In other words, a lower CO limit would

impose additional compliance burden with no corresponding reduction in HAP

emissions.

We note that EPA asserts in the proposed rule that, “When the available formaldehyde

emission information is ranked and the best performing 12 percent identified, the

mathematical average of the best performing units’ corresponding CO emission levels is

240 ppm which is in the range, previously indicated, that formaldehyde emission levels

are lowest.” 80 Fed. Reg. at 3096 (col. 2). In other words, EPA provides an alternative

justification for setting the CO standard at 130 ppm. In addition to representing the

point at which HAP combustion is essentially complete, 130 ppm also represents the

numeric MACT floor for existing sources. We support this alternative basis for the 130

ppm standard and further suggest that an “above the floor” standard is not warranted

here because making the 130 ppm limit more stringent would not accomplish any

significantly greater HAP reductions.

VI. Comments on Technical Changes

A. Changes to Output Based Limits

The proposed changes to the output based limit provisions and the additional equation

(Equation 21) are appropriate and provide the needed clarification to allow multi-use

units and units that provide steam to common headers to explore this compliance

option. We note that the term “common heaters” in 63.7500(a)(1) should be changed to

“common headers.”

B. Load Operating Parameter

The Boiler MACT rule requires facilities to establish various operating parameter limits

during the initial performance test and then monitor those operating parameters as

ongoing compliance indicators. Most operating parameters are established based on a

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minimum or maximum hourly average during the initial performance test and have a 30-

day averaging period for ongoing monitoring. The 30-day averaging period accounts for

variability in boiler/process heater operation. One such operating parameter is

boiler/process heater load.

We appreciate the language that EPA has proposed in Table 8 of the rule to clarify that

the 30-day averaging period applies to this parameter. We note that this change also

needs to be made in Table 4, Item 8 (add “30-day average” prior to “operating load”).

Averaging periods are appropriate for operating parameters because the standards

apply during all operating conditions (excluding startup and shutdown), and operating

conditions of industrial boilers and process heaters can be highly variable, especially

when fuel mix and load change. The operating parameter ranges will be established

using test data obtained at steady state, so a 30-day averaging period allows for some

fluctuations that will occur over the range of operating conditions. EPA correctly pointed

out that variability outside the operator’s control such as fuel content, seasonal factors,

load cycling, and infrequent hours of needed operation give cause to use a longer

averaging period (76 Fed. Reg. 80610).

Although many boilers and process heaters operate at fairly constant loads over the

course of a 3- to 6-hour performance test, some units provide steam, heat, or both to

processes with variable requirements, such as a lumber kiln or other batch process.

For facilities that only utilize one boiler or process heater to serve a particular process, it

may not be possible to operate at the maximum operating load for an entire stack test

without having to vent or “waste” steam not continuously required by process or

processes served by the unit (if the unit is even capable of this type of practice). This

would waste energy at a time when energy costs are high and it is the goal of both the

agency and industry to conserve energy, not waste it.

Along the same lines, if there is no averaging period associated with the operating load

requirement, processes that require variable steam or heat could cause the boiler or

process heater to instantaneously operate at greater than 110 percent of the average

operating load corresponding to the most recent 3- to 6-hour stack test due to a swing in

instantaneous process steam demand or heat requirement. An undesirable outcome

would be numerous meaningless “deviations” from the load operating parameter range

during these short-term operating periods. These false deviations would be completely

avoided with the application of the appropriate averaging period and would not be

accompanied by any deviations from other operating parameter requirements (or

emissions for units with CEMS) due to the application of a 30-day averaging period on

almost every other operating parameter and on emissions measured by CEMS. In

fact,§ 63.7525(d)(4), which covers requirements for operating limits that require use of a

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CPMS other than PM CPMS or COMS, states “you must determine the 30-day rolling

average of all recorded readings…”

However, there are still inconsistencies in the rule tables that must be clarified. The

language in Tables 4 (which states what operating limits must be met) and 8 (which sets

forth requirements for demonstrating continuous compliance) conflicts with the language

in Table 7 (which describes how operating limits are to be established). Table 4, item 8,

states that if you are demonstrating compliance using performance testing, you must

“maintain the operating load of each unit such that it does not exceed 110 percent of the

highest hourly average operating load recorded during the most recent performance

test.” Table 8, item 10, requires “Maintaining the 30-day rolling average operating load

such that it does not exceed 110 percent of the highest hourly average operating load

recorded during the most recent performance test according to 63.7520(c).” Section

63.7520(c) refers to the language in Table 4. However, Table 7, item 5, states that you

“Determine the average of the three test run averages during the performance test,

and multiply this by 1.1 (110 percent) as your operating limit.” Therefore, there is a

conflict as to whether you use the highest hourly average operating load times 1.1 as

the operating limit or the test average operating load times 1.1 as the operating limit.

For consistency with other operating parameter limits and to avoid inappropriately

limiting boiler/process heater throughput, Table 7, item 5 should be revised to clearly

state that the limit is set based on the highest hourly average during the test times 1.1.

We would also appreciate further clarification regarding how to set the operating

parameters such as load when multiple performance test conditions are required to

demonstrate compliance and there are multiple operating scenarios that could occur.

Take for example a 500 MMBtu/hr solid fuel boiler that is permitted to burn biomass at

full capacity but can only burn coal up to 249 MMBtu/hr. The performance test for PM

would be conducted at a load as close to 500 MMBtu/hr as possible. However, the test

for mercury could be conducted while burning only coal at 249 MMBtu/hr in order to

achieve the highest mercury emission rate on a lb/MMBtu basis. If this unit is equipped

with a wet scrubber, the differential pressure at 249 MMBtu/hr on coal is going to be

different than that while operating at 500 MMBtu/hr, especially with a fixed throat venturi

scrubber, where differential pressure is directly proportional to flue gas flow. Likewise, if

the unit has the ability to burn 500 MMBtu/hr natural gas, compliance with control device

operating ranges should not be required during this mode of operation. The language

for setting scrubber operating parameters is clear on what test to use if multiple tests

are performed, but should also indicate that the facility has the option to set multiple

operating parameter ranges if there are multiple operating scenarios expected that will

affect the facility’s ability to comply with a single range. The language for setting the

operating load limit should indicate that it if multiple tests are done, the limit should be

set based on the highest hourly average operating load achieved across all the tests.

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Section 63.7540(a)(1) states “operating limits must be confirmed or reestablished during

performance tests.”. Boiler and process heater operators typically operate with a

compliance margin, not right at the operating ranges, so we agree that it is an

appropriate option for us to confirm our operating limits, rather than continually

ratcheting down our operating parameters with each annual test, as long as the initial

performance test conditions are representative of continuing operations. However, we

believe that a technical correction is needed in Table 8 to address a conflict with this

language. EPA should revise the wording in Table 8, Lines 9.c, 10.c, and 11.c to be

consistent with the wording in Lines 2.c, 4.c, 5.c, 6.c, and 7.c.

C. O2 Trim System Requirements

There are three options for monitoring for compliance with an applicable CO limit:

monitoring CO using a CO CEMS, continuous O2 monitoring with the O2 level

determined by a CO stack test, or use of an automatic O2 trim system with a set point

determined by a CO stack test. EPA has attempted to clarify the monitoring

requirements for compliance with the CO limits in 63.7525. However, we believe the

proposed changes add further confusion over whether the 3 options overlap. The

change in paragraph 62.7525(a) that clarifies that facilities with CO CEMS do not also

have to operate an O2 trim system by removing the reference to paragraph (7) is

appropriate. However, the revised language in 63.7525(a)(7) can be read to add

requirements to facilities that do not have a CO limit (e.g., gas 1 units with O2 trim

systems) or extra burden for facilities that are using a CO CEMS but also operate an O2

trim system and qualify for a 5-year tune-up frequency. The added phrase is

unnecessary and should be struck for units with emission standards. A facility operating

a CO CEMS as a direct measure of compliance with the applicable CO limit should not

also be subject to an operating limit for O2.

A facility with a unit that is not subject to emission standards (i.e., Gas 1 unit) may

choose to operate an oxygen trim system to reduce the tune-up frequency of the unit to

once every 5 years. If it was EPA’s intent to provide guidance for those units on how to

operate the O2 trim system, the following phrase should be added to the end of

63.7540(a)(12):

“If an oxygen trim system is utilized on a unit without emission standards to

reduce the tune-up frequency to once every 5 years, set the oxygen level no

lower than the oxygen concentration measured during the most recent tune-up.”

D. Fuel Sampling Requirements and Compliance

Tables 4, 6, and 8 in the rule outline the requirements around fuel analysis for: setting

operating limits, conducting fuel analysis, and demonstrating continuous compliance.

EPA has proposed several changes to Table 6 of the rule in an effort to clarify the

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requirements around ongoing compliance using fuel analysis. However, further

changes are required in Tables 4, 6, and/or 8 to eliminate inconsistencies between the

regulations and the tables and to provide references to the correct equations.

Tables 4 and 8 – Operating Limits & Demonstrating Continuous Compliance

Table 4, Line 7 notes that the operating limit requirement for units demonstrating

compliance using fuel analysis is to “maintain the fuel type or fuel mixture such that the

applicable emission rate calculated according to 63.7530(c)(1), (2), and/or (3) is less

than the applicable emission limit.” This language is in conflict with Table 8 and should

be adjusted to simply require the operator to “maintain the fuel type or fuel mixture such

that the applicable emission rate is less than the applicable emission limit.” The

requirements in section 63.7530 pertain to the initial performance test, not ongoing

compliance. Continuous compliance is covered in section 63.7540, and 63.7540(a)(2)

requires that the fuel or mixture of fuels burned results in lower emissions of HCl,

mercury, and TSM than the applicable emission limit for each pollutant, if you

demonstrate compliance through fuel analysis. Each unit must demonstrate continuous

compliance with the operating limits in Table 4 utilizing the methods in Table 8. Line 8

of Table 8 outlines the process for continuous compliance with fuel analysis.

Specifically, the 12-month rolling average pollutant input (lb/MMBtu), based on monthly

averages, must be below the emission limits in Table 1, 2, 11, 12 or 13.

It is agreed that a rolling 12-month average is the correct averaging period for

demonstrating continuous compliance. However, there is a disconnect between the

operating limit in Table 4 (that references the 90th percentile equations used to set the

maximum fuel pollutant input levels) and the methods to demonstrate compliance in

Table 8 (actual measurements of monthly average fuel pollutant content).

Table 6 – Fuel Analysis Requirements

Table 6 is referenced for two different compliance approaches:

Fuel analysis required as part of the initial performance test for those multi-fuel

units that comply using performance stack testing: 40 CFR 63.7530(b) refers to

40 CFR 63.7521; 63.7521(a) states that fuel analysis must follow the procedures

in Table 6.

Fuel analysis required for initial and continuous compliance for those units that

use monthly fuel analysis as their compliance approach: compliance procedures

are provided in 40 CFR 63.7530(c) and 40 CFR 63.7540(a), which include setting

operating limits in Table 4 and using the methods in Table 8; note that Table 8

line 8(a) requires the facility to collect samples for fuel analysis according to

Table 6.

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Therefore, the requirements in this table should outline the procedures for sample

collection, preparation, and measurement of the concentration of the pollutant in the

fuel. With this approach, the deletion of Lines 1(h), 2(h), and 4(h) is appropriate.

Table 6, Lines 1(g), 2(g), and 4(g) are necessary to convert concentrations of each

pollutant into lb/MMBtu heat content. However the references to Equations 7, 8, and 9

in 63.7530 are incorrect. In fact, there are no equations in the rule that convert

concentration into lb/MMBtu; therefore, while step (g) is necessary, the references to

these equations should be deleted.

Amendment to 40 CFR 63.7530

EPA has recommended adding language to the definition of variable Qi in

63.7530(b)(1)(iii), 63.7530(b)(2)(iii), and 63.7530(b)(3)(iii). This language should also

be added to the definition of variable Qi in section 63.7530)(c)(3), (c)(4), and (c)(5):

“For continuous compliance, the actual fraction of fuel burned during the month

should be used.”

Timing of Fuel Sampling

EPA has proposed to remove the requirement at 63.7521(c)(2)(ii) that requires monthly

composite fuel samples to be collected at 10-day intervals during the month. We

support this change because it is not always possible to take 3 samples at 10-day

intervals in 1 month. However, we would appreciate a clarification on whether we are to

take one composite sample that consists of 3 individual samples or 3 composite

samples that consist of 3 individual samples. The language at 63.7521(c) states “three

composite fuel samples” will be obtained, but 63.7521(c)(2)(ii) states that “each

composite sample will consist of a minimum of three samples collected at approximately

one-hour intervals during stack testing.” This sentence is a little confusing, in that it

could be interpreted that only 3 total samples (1 per run) are required, which is in

conflict with the language in 63.7521(c). An appropriate clarification might be: “During

performance stack testing, one composite sample will consist of a minimum of three

samples collected of over each of three individual stack testing runs during the testing

period for sampling during performance stack testing,” since not all stack testing runs

are 1 hour in length.

Section 63.7515(e) states that a facility may comply with the monthly fuel analysis

requirement “by completing the fuel analysis any time within the calendar month as long

as the analysis is separated from the previous analysis by at least 14 calendar days.”

This requirement does not acknowledge that a facility may choose to collect and

analyze multiple samples in a month (e.g., with each shipment of coal). The rule should

be clear that if sampling is conducted on one day per month, samples should be no less

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than 14 days apart, but if multiple samples are taken per month, the 14-day restriction

does not apply.

E. pH Performance Evaluation – Proposed Change to “Calibrate”

EPA proposes to change the language in 63.7525(g)(3) from “Conduct a performance

evaluation of the pH monitoring system in accordance with your monitoring plan at least

once each process operating day” to “Calibrate the pH monitoring system in accordance

with your monitoring plan at least once each process operating day.” Although a facility

may choose to calibrate the pH monitoring system each day, the proposed change is

overly prescriptive and the existing language should remain.

Many facilities use alternate methods to confirm the accuracy of the pH readings and

these methods should not be eliminated. For example, it may require additional safety

precautions to remove the pH probe from the sample stream. In this instance, the

approach would be to take a sample of the scrubbing liquid and analyze the pH using a

calibrated portable pH probe. If the reading from the portable pH probe was not within

the accuracy limits of the in-line compliance pH probe (the CMS device), then the in-line

probe would be removed for calibration. These procedures would be outlined in the

Site-Specific Monitoring Plan as required under 63.7505(d)(1).

F. Timing for Compliance After Modifications in 63.7495(h)

EPA has proposed to add section 63.7495(h), which states “If you own or operate an

existing industrial, commercial, or institutional boiler or process heater and have switch

fuels or made a physical change to the boiler or process heater that resulted in the

applicability of a different subcategory after January 31, 2016, you must be in

compliance with the applicable existing source provisions of this subpart on the effective

date of the fuel switch or physical change.” As some sources have received a 1-year

compliance extension, we request substituting “the compliance date of this subpart” for

“January 31, 2016” to cover sources that might be making changes between

January 31, 2016 and the extended compliance date of January 31, 2017.

G. Applicability to Gas-Fired EGU’s

EPA has proposed to further clarify at 63.7491(a) that the Industrial Boiler MACT does

not apply to EGU’s. We agree with the proposed change as it reflects EPA’s finding

that HAP emissions from gas-fired EGU’s do not pose a threat to public health and

should not be regulated under the MACT program.

H. Clarification Regarding Submittal of Other Gas 1 Fuel Sampling Plan

EPA has proposed to clarify at 63.7521(g) that submittal of every site-specific fuel

analysis plan for other gas 1 fuels is not necessary because 63.7521(g)(1) only requires

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site-specific fuel analysis plans to be submitted for review and approval if an alternate

method will be used. We support this change as it is consistent with the requirements

for other fuels.

I. Load Fraction

EPA has proposed to clarify the definition of load fraction at 63.7575. The proposed

clarification to the load fraction definition is appropriate because it recognizes that the

fraction of heat input from gas firing does not contribute to mercury, SO2, or HCl

emissions and should not be factored into the sorbent injection rate for mercury or acid

gas control.

J. Hybrid Suspension Grate CO limit

EPA has proposed to change the biomass hybrid suspension grate CO limit to correct a

mathematical error they made in calculating the limit. The need for this change was

pointed out by other industry commenters and we support this change as an appropriate

technical correction.

K. Clarification is Needed on Reporting 30-day and 10-day Average Values for CEMS and CPMS

EPA has proposed various revisions to the reporting requirements at 63.7550(c). Section 63.7550(c)(5) states that compliance reports must include all of the calculated 30-day rolling average values based on the daily CEMS and CPMS data. The requirement to report all 30-day average values in the compliance report is overly burdensome and adds little value since facilities are already required to provide information on any deviations that may have occurred as required in 63.7550. (In addition, we note that not all of the parameters that might be monitored by CPMS are included in the list of values to be reported at 63.7550(c)(5)(xvi); only PM CPMS and scrubber parameters are listed.) The information on monitoring deviations will be sufficient for the agency to evaluate compliance with the rule without submittal of all the underlying data. Industry is not required to submit all monitored values under other MACT rules. The requirement to report all of the monitored values in the report creates extra burden that provides no additional benefit. The agency can request additional information or come onsite to view the monitoring systems and data if more detail is needed for a specific facility.

L. Opacity Operating Parameter Limit

Under Subpart DDDDD, affected sources that use a dry ESP to comply with the PM

limit and that do not use a PM CPMS are required to continuously monitor opacity and

maintain opacity below 10% on a daily block average basis. EPA has proposed a

technical correction to Table 4, Line 4, that removes the “or” between items (a) and (b)

to indicate that items (a) and (b) are two different regulatory situations, not that facilities

have a choice of how to monitor units with ESPs that don’t use PM CPMS. The 10%

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opacity level is an “operating limit,” not a standard, and is utilized as an indicator of

compliance with the Boiler MACT PM limit. Operating limit requirements are provided in

Table 4 of Subpart DDDDD, and include opacity. Emission limits are included in Tables

1 and 2 of the rule and do not include opacity.

Opacity measurements are impacted by particle characteristics, which can cause

inconsistent correlation of opacity to actual mass based particulate emissions between

combustion units (in other words, two boilers with the same PM emission rate could

experience significantly different opacity levels). Variations in particulate characteristics

such as density, color, luster, size, and shape impact the level to which the optical beam

is diffracted or absorbed by entrained particles as it travels back and forth across the

flue gas path. Opacity monitoring systems are unable to address these variations in

particle characteristics and thus provide no correction for them in the opacity

measurement technique. Therefore these particle characteristics can and should be

considered interferences in establishing a “one-size-fits-all” correlation to mass based

particulate emissions from multi-fuel fired boilers. Particle characteristics can be

influenced by a variety of boiler parameters including boiler design, fuel source,

operating load, and boiler operating practices that are specific to a given unit. Because

PM limits for existing solid fuel boilers range from 0.02 – 0.44 lb/MMBtu, a single 10%

opacity level is not necessarily appropriate as a monitoring parameter for all

subcategories. The 10% opacity operating parameter limit may be an appropriate

indicator of compliance with the applicable Boiler MACT PM limits for some boilers, but

it is not an appropriate indicator of compliance for all boilers in all solid fuel

subcategories.

In response to a comment from Norbord Industries (EPA-HQ-OAR-2002-0058-0854.1)

questioning how the 10% opacity limit was set, EPA responded as follows:

Opacity is often required in CAA rules as a surrogate for PM to assure

compliance with PM standards when continuous PM monitoring is not

required under the applicable standard. The 10 percent operating limit is in

the general range of other opacity limits for combustion rules.

Therefore, EPA did not establish the opacity operating parameter level of 10% in the

same manner in which it determined the numeric PM emission limits, but it established

an operating parameter limit that it believed would be a good indicator of compliance

with the PM limit.

Facilities can petition for an alternative operating limit using the procedures found in

63.8(f). The Boiler MACT citation outlining this authority and procedure for submitting

such requests is provided below:

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§63.7500 What emission limitations, work practice standards, and operating limits must I meet?

(a)(2) You must meet each operating limit in Table 4 to this subpart that applies to your boiler or process heater. If you use a control device or combination of control devices not covered in Table 4 to this subpart, or you wish to establish and monitor an alternative operating limit or an alternative monitoring parameter, you must apply to the EPA Administrator for approval of alternative monitoring under §63.8(f).

In recent discussions between EPA and an affected facility that submitted a request for

an alternate opacity operating limit, EPA stated that they wanted the facility to instead

follow the procedures in 63.7570(b)(2), which states that approval of alternative opacity

emission limits in 63.7500(a) is done per 63.6(h)(9). This is not an appropriate

approach because 10% opacity is not an emission limit. (There are other Part 63

standards that include opacity emission limits, such as Subpart EEE, but not

Subpart DDDDD.) We did not previously comment on this issue because it was not

reasonable to interpret the 10% opacity operating parameter limit as an emission limit

as it is located in the table of operating parameter limits, not the tables of emission

limits. By requiring the Herculean effort of a separate rulemaking per 63.6(h) to set an

alternate opacity operating parameter limit, EPA is effectively subjecting units to a more

stringent PM standard than the established MACT floor as this process will not be

feasible to complete prior to the compliance date. Facilities can adequately

demonstrate to EPA through the 63.8(f) process that a higher opacity level can be

appropriate for specific situations.

To resolve this issue, EPA must delete 63.7570(b)(2) so it will be clear that a request for

an alternate opacity operating parameter limit is accomplished under § 63.8(f) per

63.7570(b)(4) and 63.7500(a)(2).

M. Additional Technical Edits Requested

The requirement to monitor “liquid to fuel” ratio under 63.7555(d)(12)(iii) should be changed to “liquid to flue gas ratio” if these extra monitoring requirements are retained for the second definition of startup, although we would like to note that most facilities with scrubbers do not currently monitor flue gas flow rate, so this is a significant addition to the monitoring burden. The requirement to monitor “differential pressure of the liquid” should be dropped.

If EPA retains the additional startup monitoring requirements, the language in 63.7555(d)(12) for parameters like voltage, current, pressure drop, and flow should indicate that the hourly values to be recorded are averages during the hour or portion of the hour the unit is in startup.

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The following are suggested additions/edits to the fuel analysis methods in Table 6:

o ASTM E1757 for biomass sample preparation

o ASTM D7582 and ASTM E1064 for moisture

o ASTM D4809 for heat content of liquid fuels

o Move EPA 1631, EPA 1631E, and EPA 821-R-01-013 from Line 1.a to 1.f because these methods cover the analytical method, not the sample collection method.

o Remove ASTM D4177 and D4057 from Line 1.e and 2.e because these are sampling methods, not methods for determining moisture.

EPA has proposed various revisions to the extensive and onerous reporting requirements at 63.7550(c). We would like to note that the required reporting at 63.7550(c)(xvi) includes 30-day average CEMS data but not any 10-day average CEMS values and does not include daily opacity values, although it includes all other parameter values and will make for a very lengthy report. While we believe it is not necessary to require reporting of all monitored parameter values and that reporting of deviations should suffice, if EPA intends to require every single monitored value to be reported, this provision should be updated to include 10-day average CO CEMS values and opacity data as well, for consistency.

EPA should add process heaters to all citations in the regulation that only

reference boilers. For example, process heaters were inadvertently omitted in

the first two parts of the definition of energy assessment in § 63.7575:

Energy assessment means the following for the emission units covered by this

subpart:

(1) The energy assessment for facilities with affected boilers and process

heaters with a combined heat input capacity of less than 0.3 trillion Btu

(TBtu) per year will be 8 on-site technical labor hours in length maximum,

but may be longer at the discretion of the owner or operator of the affected

source. The boiler system(s), process heater(s), and any on-site energy

use system(s) accounting for at least 50 percent of the affected boiler(s)

or process heater(s) energy (e.g., steam, hot water, process heat, or

electricity) production, as applicable, will be evaluated to identify energy

savings opportunities, within the limit of performing an 8-hour on-site

energy assessment.

(2) The energy assessment for facilities with affected boilers and process

heaters with a combined heat input capacity of 0.3 to 1.0 TBtu/year will be

24 on-site technical labor hours in length maximum, but may be longer at

the discretion of the owner or operator of the affected source. The boiler

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system(s), process heater(s), and any on-site energy use system(s)

accounting for at least 33 percent of the energy (e.g., steam, hot water,

process heat, or electricity) production, as applicable, will be evaluated to

identify energy savings opportunities, within the limit of performing a 24-

hour on-site energy assessment.

VII. Conclusion

We appreciate the opportunity to submit these comments on the proposed changes to

the Industrial Boiler MACT rule. We urge EPA to finalize the rule as quickly as possible

while it reconsiders the affirmative defense/malfunction issue discussed in section III, so

our members can have adequate time prior to the rapidly approaching compliance date

to make operational decisions and update their compliance systems. If you have any

questions about these comments or need additional information or clarification, please

do not hesitate to contact Tim Hunt of AF&PA at 202-463-2588. We would be pleased

to engage in further dialog with you on the importance of finalizing startup requirements

that we can safely and successfully implement.

Attachment 1. Excerpt from ESP Operating Manual

Attachment 2. Excerpt from Recently Installed ESP Operating Manual