Comments on the National Emission Standards for

Hazardous Air Pollutants for Major Sources:

Industrial, Commercial, and Institutional Boilers and

Process Heaters: Non-Continental Liquids Subcategory

July 15, 2011

Mr. Brian Shrager

Energy Strategies Group, Sector Policies and Programs Division, (D243–01)

Office of Air Quality Planning and Standards

U.S. Environmental Protection Agency

Research Triangle Park, North Carolina 27711

shrager.brian@epa.gov.

Dear Brian:

The final National Emission Standards for Hazardous Air Pollutants for Major Sources:

Industrial, Commercial, and Institutional Boilers and Process Heaters (76 Fed. Reg. 15608, 

March 21, 2011) established a subcategory for units designed to burn liquid fuel that is a noncontinental unit (i.e., an industrial, commercial, or institutional boiler or process heater designed 

to burn liquid fuel located in the State of Hawaii, the Virgin Islands, Guam, American Samoa, 

the Commonwealth of Puerto Rico, or the Northern Mariana Islands.) That regulation is 

currently stayed pending reconsideration1

. API/NPRA filed a reconsideration petition on May 

20, 2011 detailing the broad list of issues that we believe require review.

API and NPRA members operate many boilers and process heaters in non-continental locations. 

Because there is no practical access to natural gas in non-continental locations, many of these 

units must fire liquid fuels or fire liquids when internally generated gases are unavailable. Thus, 

we are vitally interested in assuring that the applicable requirements for the Non-Continental 

Liquids Subcategory are reasonable, achievable, and cost effective. To further the 

reconsideration process, API and NPRA offer the following comments as a supplement to our 

May 20, 2011 petition and data to improve the basis for the emission limitations established for 

the Non-Continental Liquids Subcategory.

 1 76 FR 15266 (March 21, 2011)
API/NPRA Comments on Non-Continental Liquids Subcategory Page 2

1. The regulation establishes a numerical emission limit for particulate (PM) of 0.0075 lb per 

MMBTU of heat input (30-day rolling average for residual oil fired units 250 MMBTU/hr or 

greater, 3-run average for other units) for existing units and 0.0013 lb per MMBTU of heat input 

(30-day rolling average for units 250 MMBTU/hr or greater, 3-run average for units less than 

250 MMBtu/hr) for new units. These limits were established based on the data available for the 

Continental Liquids Subcategory because the Agency did not have any PM test data for noncontinental units (Chevron data for a non-continental process heater were submitted after the 

close of the public comment period). Attached as Attachments 1, 2 and 3 are PM test reports for 

three Non-Continental Liquids Subcategory unit tests (a Chevron process heater and two tests on 

a Tesoro boiler) for your use in establishing limits specific to this subcategory. These test 

reports confirm there is considerable variability between units, which reflects the differences in 

the fuels non-continental units must feed (i.e., fuels produced in their own refining operations) 

and the different burner designs that result from having to have the capability to burn both liquid 

and gaseous fuels. In this case, the Tesoro boiler can burn either liquid or gaseous fuels, but not 

at the same time; while the Chevron process heater can fire both liquid and gaseous fuels in the 

same burners at the same time (though it was only burning fuel oil during this test). It is critical 

that the variability reflected in these test reports be appropriately addressed in developing the PM 

limitation for the Non-Continental Liquids Subcategory.

Applying the same approach to variability to these Non-Continental Liquid units as was done for 

the Continental Liquids subcategory, and as described in ERG’s memo “Revised MACT Floor 

Analysis (2011) for the Industrial, Commercial, and Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants – Major Source,” results in a 

calculated upper prediction limit (UPL) of 0.31 lb per MMBTU of heat input at a 99% 

confidence level2

. Basing the existing source PM standard on this calculated UPL is a 

reasonable approach for EPA to use in addressing the variability of PM emissions from these 

specific units.

In consideration of the best performing source for establishing the PM standard for new sources 

in the Non-Continental Liquid Subcategory, it is important to note that the fuel for the top ranked 

unit (Tesoro’s SG-1102) is specific to the Tesoro refinery and cannot be reasonably purchased or 

obtained by other sources in the subcategory. Consistent with the HCl MACT floor for new 

boilers designed to burn liquid fuel, the Hg MACT floor for new boilers designed to burn solid 

fuel, and the CO MACT floor for new fluidized bed boilers designed to burn biomass, and as 

described in ERG’s previously-cited memo (page 24), we request that EPA utilize the next 

lowest emissions as the basis for the floor calculations. Using the second lowest test average for 

the PM MACT floor for new Non-Continental Liquid units results 0.078 lb per MMBTU, based 

on the calculated 99% UPL2

 2 The calculation of these recommendations is shown in Attachment 4, which provides the new information and calculations in 

the same format used by EPA in the floor analysis supporting the stayed rule.

. 
API/NPRA Comments on Non-Continental Liquids Subcategory Page 3

2. The regulation establishes a numerical emission limit for Mercury (Hg) of 7.8E–07 lb per 

MMBTU of heat input for both existing and new units. 

The data for mercury for non-continental unit fuels that served as the basis for the numerical 

emission limit is very limited. We have located data on four additional samples from two other 

non-continental refineries and provide it as Attachments 5 and 6. Because non-continental 

refineries are using fuels that they produce there is considerable variation in mercury emissions 

over time and between non-continental refineries. Basing the Hg limit on a few samples from 

only one refinery (as was done for the stayed rule) without considering inter-refinery variability 

due to fuel and crude constraints, virtually assures significant compliance challenges for all other 

non-continental refineries. Furthermore, since these refineries are the only sources of supply for 

non-refinery boilers and process heaters at non-continental locations, establishing a limit that 

some refinery units in non-continental locations cannot meet means many non-refinery units will 

also be unable to meet them. We encourage EPA to consider carefully the potential impacts on 

island economies of setting unattainable Hg limits or of unnecessarily forcing expenditures for 

mercury and the associated PM controls on many non-continental boilers and process heaters.

There are significant issues associated with the measurement of mercury that need further 

consideration. The data for mercury for non-continental unit fuels that served as the basis for the 

numerical emission limit in the stayed rule were from a single refinery and were determined

using a method not delineated as an approved method in Table 6 of the rule. The results from 

this different method indicated mercury levels far below the typical detection limit of the method 

prescribed in Table 6 (EPA SW-7471B), as shown in the additional samples attached to this 

letter. The use of unapproved methods and methods where sample times have been extended 

show the difficulty of measuring mercury in fuels at the low levels typically present. Having to 

resort to such approaches demonstrates that the application of measurement methodology for 

mercury to non-continental unit fuels is not practicable. We encourage EPA to consider a work 

practice standard as an appropriate standard for mercury for non-continental units, analogous to 

their conclusion for the Gas 1 subcategory.

3. The regulation establishes a numerical emission limit for carbon monoxide (CO) of 160 ppm 

by volume on a dry basis corrected to 3 percent oxygen for existing units and 51 ppm by volume 

on a dry basis corrected to 3 percent oxygen for new units. Compliance is demonstrated by an 

initial CO performance test and continuous monitoring of the oxygen content of the unit exhaust 

gas versus an O2 parameter established during the CO performance test. 

Stack O2 measurements, as apparently required by specifying that the analyzer be in the “exhaust 

gas,” are not always the best indicator of CO and organic HAP emissions because they are 

influenced by air leakage into the unit. This is a particular concern for process heaters, because 

they typically have many more potential leak locations than does a boiler and because they often 

run at a negative pressure. Thus, in many cases existing O2 monitors are located in the radiant 

section roof or at another location as near to the firebox as possible, considering sensor 

temperature constraints and the need for safe access for testing and maintenance while the boiler 

or process heater is in operation. The regulation should allow flexibility in locating the O2

analyzer, as long as a representative location is selected, since every boiler and process heater is 
API/NPRA Comments on Non-Continental Liquids Subcategory Page 4

designed and operated differently. The regulation language should be clear that this is a 

modification from, and overrides, the location specification in Part 60 Performance Specification 

3, which has a different purpose (i.e., determining stack gas O2 for the purpose of correcting 

measured stack emissions to standardized O2 levels.)

Additionally, the regulation should allow the use of CO analyzers or Total Combustibles 

analyzers as an alternate to oxygen analyzers, since some units already have such analyzers. 

While O2 monitoring will provide continuing compliance assurance at the most reasonable cost, 

direct measurements should be allowed where the instrumentation already exists.

4. The regulation establishes a numerical emission limit for dioxins/furans (D/F) of 4 ng/dscm 

(TEQ) corrected to 7 percent oxygen for existing units and 0.002 ng/dscm (TEQ) corrected to 7 

percent oxygen for new units. As with PM, there was no test data from non-continental units for 

D/F available to the Agency; thus, the limit for the Non-Continental Liquids Subcategory was set 

equal to the limit derived for the Continental Liquids Subcategory. 

In the proposed Electric Utility NESHAP rulemaking3

, EPA concluded that “The significant 

majority of measured emissions from EGUs of these HAP were below the detection levels of the 

EPA test methods, and, as such, EPA considers it impracticable to reliably measure emissions 

from these units. As the majority of measurements are so low, doubt is cast on the true levels of

emissions that were measured during the tests. Overall, 1,552 out of 2,334, total test runs for 

dioxin/furan organic HAP contained data below the detection level for one or more congeners, or 

67 percent of the entire data set. In several cases, all of the data for a given run were below the 

detection level; in few cases were the data for a given run all above the detection level.” A work 

practice standard (unit tune-ups) was therefore proposed to address D/F under the authority of 

Section 112(h) of the Clean Air Act (CAA). A similar conclusion was reached in that proposal 

for organic HAP. In that case EPA concluded that “For the non-dioxin/furan organic HAP, for 

the individual HAP or constituent, between 57 and 89 percent of the run data were comprised of 

values below the detection level. Overall, the available test methods are technically challenged, 

to the point of providing results that are questionable for all of the organic HAP. ... Based on the 

difficulties with accurate measurements at the levels of organic HAP encountered from EGUs 

and the economics associated with units trying to apply measurement methodology to test for 

compliance with numerical limits, we are proposing a work practice standard under CAA section 

112(h).”

We believe the D/F dataset for liquid-fired boilers and process heaters demonstrates the same 

problems as the Electric Utility dataset demonstrates for D/F and for organic HAP and that, 

therefore, the standard for D/F under the Boiler and Process Heater NESHAP should also be a 

work practice (e.g., a tune-up work practice as is proposed for electric utility units).

 3 76 Fed. Reg. 24976, May 3, 2011
API/NPRA Comments on Non-Continental Liquids Subcategory Page 5

The dataset used to establish the BPH Liquid D/F limit, and thus the non-continental liquid D/F 

limit, is comprised of data from 13 continental sources. Two sources comprised the top 12% of 

this dataset and thus were the basis for the MACT floor determination. As shown in Appendix 

D-3 of the floor analysis4, for one of the floor units all 51 measurements of individual D/F 

compounds were non-detects. For the other unit, 31 of 51 individual D/F compounds were nondetects. Thus, the D/F limit for liquid fired units in the stayed rule is based on data in which only 

20 of 102 measurements detected the D/F compound being measured. This 20% rate is lower 

than the 33% D/F detection rate that EPA considered impracticable to reliably measure 

emissions from electric utility units and consistent with the 11 to 43% detection rate for organic 

HAP that EPA also concluded made it impractical to measure for electric utilities.

As with electric utility units, it is likely that D/F formation is inhibited by the high sulfur to 

chlorine ratios in the liquid subcategory fuels5

. Thus, as EPA found for the electric utility 

boilers, the very low generation of D/F and the difficulty of measuring D/F emissions from 

boilers and process heaters firing liquids would be expected to continue, even if additional data is 

gathered. 

5. The definition of “unit designed to burn liquid fuel” in the stayed rule specifically notes that 

“Gaseous fuel boilers that burn liquid fuel during periods of gas curtailment or gas supply 

emergencies of any duration are also not included in this definition.” The driver for this 

exclusion appears to be based solely on continental units preferentially burning natural gas 

delivered via a pipeline, except when unavailable, and allowing such units to remain under the 

“unit designed to burn gas 1 subcategory.” This exclusion qualifier, while appropriate for 

continental units, does not take into account similar non-continental facility restraints. Although 

non-continental facilities do not have access to natural gas pipelines, many non-continental units 

are subject to a comparable situation – they preferentially burn gaseous fuel, but utilize liquid 

fuel when there is insufficient availability of the gaseous fuel. For example, a boiler or process 

heater at a non-continental refinery may primarily fire refinery gas, but also fires fuel oil when 

the refinery gas supply is insufficient, such as during production unit turnarounds at the refinery. 

This is analogous to continental gaseous fuel units firing oil during periods of natural gas 

curtailment. However, the stayed rule does not provide this exclusion from the “unit designed to 

burn liquid fuel that is a non-continental unit” subcategory. We request EPA provide a similar 

exemption for non-continental gaseous fuel boilers and process heaters. The following text is 

suggested to be added to the “unit designed to burn liquid fuel that is a non-continental unit” 

subcategory definition: 

Non-continental boilers and process heaters that preferentially burn natural gas, 

refinery gas, and/or other gas 1 fuels when available but burn liquid fuel at less than 

50% of the annual heat input to the unit when natural gas, refinery gas, and/or other 

gas 1 fuel availability is insufficient are not included in this definition.

 4 Docket ID: EPA-HQ-OAR-2002-0058-3273.4 5 See discussion in Electric Utility NESHAP proposal at 76 Fed. Reg. 25023 (May 3, 2011)
API/NPRA Comments on Non-Continental Liquids Subcategory Page 6

6. In addition, EPA needs to address the annual stack testing requirement. It is a massive 

undertaking for non-continental refineries to perform tens of stack tests every year, given that 

stack testers must be brought in and samples often must be shipped to far off mainland 

laboratories. One solution would be to allow sources to skip stack testing if they are willing to 

continue to meet the continuous compliance parameter established previously. It would seem 

that a minimum oxygen level established in an initial performance test would remain a good 

indicator of good combustion (low CO and particulates) indefinitely.

If you have any questions on these comments, please contact Matt Todd at (202) 682-8319.

Sincerely,

/s/ /s/

Matthew Todd

API

toddm@api.org

(202) 682-8319

David Friedman

NPRA

dfriedman@npra.org

(202) 552-8461

Attachments