National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries, 37133-37148 [2013-14624]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 78, Number 119 (Thursday, June 20, 2013)]
[Rules and Regulations]
[Pages 37133-37148]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-14624]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2003-0146; FRL-9751-4]
RIN 2060-AP84


National Emission Standards for Hazardous Air Pollutants From 
Petroleum Refineries

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action amends the national emission standards for 
hazardous air pollutants for heat exchange systems at petroleum 
refineries. The amendments address issues raised in a petition for 
reconsideration of the EPA's final rule setting maximum achievable 
control technology rules for these systems and also provides additional 
clarity and regulatory flexibility with regard to that rule. This 
action does not change the level of environmental protection provided 
under those standards. The final amendments do not add any new cost 
burdens to the refining industry and may result in cost savings by 
establishing an additional monitoring option that sources may use in 
lieu of the monitoring provided in the original standard.

DATES: The final amendments are effective on June 20, 2013. The 
incorporation by reference of certain publications listed in the final 
rule amendments is approved by the Director of the Federal Register as 
of June 20, 2013.

ADDRESSES: The EPA has established a docket for this action under 
Docket ID No. EPA-HQ-OAR-2003-0146. All documents in the docket are 
listed in the www.regulations.gov index. Although listed in the index, 
some information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically in www.regulations.gov or in hard copy at the EPA Docket 
Center, National Emission Standards for Hazardous Air Pollutants From 
Petroleum Refineries, EPA West Building, Room 3334, 1301 Constitution 
Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 
a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The 
telephone number for the Public Reading Room is (202) 566-1744, and the 
telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Ms. Brenda Shine, Office of Air 
Quality Planning and Standards, Sector Policies and Programs Division, 
Refining and Chemicals Group (E143-01), Environmental Protection 
Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-
3608; fax number: (919) 541-0246; email address: shine.brenda@epa.gov.

SUPPLEMENTARY INFORMATION: The information in this preamble is 
organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
II. Background Information
    A. Executive Summary
    B. Background of the Refinery NESHAP
III. Summary of the Final Amendments to NESHAP for Petroleum 
Refineries and Changes Since Proposal
IV. Summary of Comments and Responses
    A. Uniform Standards for Heat Exchange Systems
    B. Refinery MACT 1 Requirements for Heat Exchange Systems
    V. Summary of Impacts
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. General Information

A. Does this action apply to me?

    The regulated category and entities potentially affected by this 
final action include:

[[Page 37134]]



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                                                   Examples of regulated
            Category             NAICS \1\  Code         entities
------------------------------------------------------------------------
Industry.......................          324110   Petroleum refineries
                                                   located at a major
                                                   source that are
                                                   subject to 40 CFR
                                                   Part 63, subpart CC.
------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be regulated by this 
final rule. To determine whether your facility is regulated by this 
action, you should carefully examine the applicability criteria in 40 
CFR 63.640 of subpart CC (National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries). If you have any questions 
regarding the applicability of this action to a particular entity, 
contact the person listed in the preceding FOR FURTHER INFORMATION 
CONTACT section.

B. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this final action is available on the Worldwide Web (WWW) through the 
Technology Transfer Network (TTN). Following signature, a copy of this 
final action will be posted on the TTN's policy and guidance page for 
newly proposed or promulgated rules at https://www.epa.gov/ttn/oarpg/. 
The TTN provides information and technology exchange in various areas 
of air pollution control.
    The EPA has created a redline document comparing the existing 
regulatory text of 40 CFR Part 63, subpart CC and the final amendments 
to aid the public's ability to understand the changes to the regulatory 
text. This document has been placed in the docket for this rulemaking 
(Docket ID No. EPA-HQ-OAR-2003-0146).

C. Judicial Review

    Under section 307(b)(1) of the Clean Air Act (CAA), judicial review 
of this final rule is available only by filing a petition for review in 
the United States Court of Appeals for the District of Columbia Circuit 
by August 19, 2013. Under section 307(d)(7)(B) of the CAA, the 
requirements established by these final rules may not be challenged 
separately in any civil or criminal proceedings brought by the EPA to 
enforce these requirements.
    Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an 
objection to a rule or procedure which was raised with reasonable 
specificity during the period for public comment (including any public 
hearing) may be raised during judicial review.'' This section also 
provides a mechanism for us to convene a proceeding for 
reconsideration, ``[i]f the person raising an objection can demonstrate 
to the EPA that it was impracticable to raise such objection within 
[the period for public comment] or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule.'' Any person seeking to make such 
a demonstration to us should submit a Petition for Reconsideration to 
the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios 
Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy 
to both the person(s) listed in the preceding FOR FURTHER INFORMATION 
CONTACT section, and the Associate General Counsel for the Air and 
Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. 
EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

II. Background Information

A. Executive Summary

1. Purpose of the Regulatory Action
    This action finalizes amendments that were proposed on January 6, 
2012, to address reconsideration issues related to the maximum 
achievable control technology standards (MACT) for heat exchange 
systems we promulgated on October 28, 2009. This action also finalizes 
additional amendments intended to clarify rule provisions and to 
provide additional flexibility.
2. Summary of Major Provisions
    We are finalizing three significant revisions to the standards for 
heat exchange systems that were promulgated on October 28, 2009. First, 
we are revising the regulations to include an alternative monitoring 
option for heat exchange systems that would allow owners and operators 
at existing sources to monitor quarterly using a leak action level 
defined as a total strippable hydrocarbon concentration (as methane) in 
the stripping gas of 3.1 parts per million by volume (ppmv); the 
current regulations (40 CFR 63.654) provide only one monitoring option, 
which requires monitoring monthly at a leak action level defined as a 
total strippable hydrocarbon concentration (as methane) in the 
stripping gas of 6.2 ppmv. We performed modeling of the monitoring 
alternative and the modeling indicates that quarterly monitoring at the 
lower leak action level provides equivalent emission reductions to 
monthly monitoring at the higher leak action level in the existing 
regulations. These amendments also include specific recordkeeping and 
reporting requirements for owners and operators electing to use the 
alternative monitoring frequency.
    The second significant amendment is the revision to the definition 
of heat exchange system to improve clarity regarding applicability of 
the monitoring and repair provisions for individual heat exchangers 
within the heat exchange system.
    The third significant revision is an amendment to the monitoring 
requirements for once-through cooling systems to allow monitoring at an 
aggregated location for once-through cooling water heat exchange 
systems, provided that the combined cooling water flow rate at the 
monitoring location does not exceed 40,000 gallons per minute.
    These final amendments do not include the proposed cross-
referencing of the Uniform Standards for Heat Exchange Systems (40 CFR 
Part 65, subpart L). These final amendments also do not include the use 
of direct water sampling methods that were proposed as alternatives to 
using the ``Air Stripping Method (Modified El Paso Method) for 
Determination of Volatile Organic Compound Emissions from Water 
Sources'' (Modified El Paso Method), Revision Number One, dated January 
2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, 
January 31, 2003 (incorporated by reference--see Sec.  63.14) within 
the Uniform Standards for Heat Exchange Systems. The EPA concluded that 
the alternative as proposed was not feasible for petroleum refineries 
and that alternatives suggested during the comment period were not 
equivalent.
3. Costs and Benefits
    The actions we are taking will have no cost, environmental, energy 
or economic impacts beyond those impacts presented in the October 2009 
final rule for heat exchange systems at petroleum

[[Page 37135]]

refineries and may result in a cost savings for refiners who select the 
proposed alternative monitoring frequency. For sources that choose the 
quarterly monitoring alternative, the cost is projected to be less than 
the cost of the monthly monitoring requirement in the October 2009 
final rule, while achieving the same environmental impacts. Similarly, 
sources that choose to monitor at an aggregated location, for the small 
number of refineries that operate once-through systems, will have 
reduced monitoring costs. The clarifications and other changes we are 
proposing in response to reconsideration are cost-neutral.

B. Background of the Refinery NESHAP

    Section 112 of the CAA establishes a regulatory process to address 
emissions of hazardous air pollutants (HAP) from stationary sources. 
After the EPA has identified categories of sources emitting one or more 
of the HAP listed in section 112(b) of the CAA, section 112(d) calls 
for us to promulgate national emission standards for hazardous air 
pollutants (NESHAP) for those sources. For ``major sources'' that emit 
or have the potential to emit any single HAP at a rate of 10 tons or 
more per year or any combination of HAP at a rate of 25 tons or more 
per year, these technology-based standards must reflect the maximum 
reductions of HAP achievable (after considering cost, energy 
requirements and non-air quality health and environmental impacts) and 
are commonly referred to as MACT standards.
    For MACT standards, the statute specifies certain minimum 
stringency requirements, which are referred to as floor requirements. 
See CAA section 112(d)(3). Specifically, for new sources, the MACT 
floor cannot be less stringent than the emission control that is 
achieved in practice by the best-controlled similar source. The MACT 
standards for existing sources can be less stringent than standards for 
new sources, but they cannot be less stringent than the average 
emission limitation achieved by the best-performing 12 percent of 
existing sources in the category or subcategory (or the best-performing 
five sources for categories or subcategories with fewer than 30 
sources). In developing MACT, we must also consider control options 
that are more stringent than the floor. We may establish standards more 
stringent than the floor based on the consideration of the cost of 
achieving the emissions reductions, any non-air quality health and 
environmental impacts and energy requirements.
    We published the first set of MACT standards for petroleum 
refineries (40 CFR Part 63, subpart CC) on August 18, 1995 (60 FR 
43620). These standards are commonly referred to as the ``Refinery MACT 
1'' standards because certain process vents were excluded from this 
source category and subsequently regulated under a second MACT standard 
specific to these petroleum refinery process vents (40 CFR Part 63, 
subpart UUU, referred to as ``Refinery MACT 2'').
    We issued an initial proposed rule to include requirements for heat 
exchange systems for the petroleum refineries subject to the Refinery 
MACT 1 on September 4, 2007, and held a public hearing in Houston, 
Texas, on November 27, 2007. In response to public comments on the 
initial proposal, we collected additional information and revised our 
analysis of the MACT floor. Based on the results of these additional 
analyses, we issued a supplemental proposal on November 10, 2008, that 
proposed a new MACT floor for heat exchange systems. A public hearing 
for the supplemental proposal was held in Research Triangle Park, North 
Carolina, on November 25, 2008. We took final action to establish 
standards for heat exchange systems in the Refinery MACT 1 standards 
(40 CFR Part 63, subpart CC) on October 28, 2009.
    On December 23, 2009, the American Petroleum Institute (API) 
requested an administrative reconsideration under CAA section 
307(d)(7)(B) of certain provisions of 40 CFR Part 63, subpart CC that 
they had identified in an April 7, 2009, letter to the EPA. On January 
6, 2012, we issued a proposed rule addressing the issues in the 
reconsideration petition and proposed amendments to 40 CFR Part 63, 
subpart CC. As part of the January 6, 2012, proposal, we also proposed 
Uniform Standards for Heat Exchange Systems (40 CFR Part 65, subpart 
L), which included the same substantive provisions for heat exchange 
systems that were in the October 2009 Refinery MACT 1 final standards 
(40 CFR Part 63, subpart CC). We proposed to remove from the Refinery 
MACT 1 standards most of the substantive provisions addressing heat 
exchange systems and to cross-reference the Uniform Standards from 
Refinery MACT 1.

III. Summary of Final Amendments to NESHAP for Petroleum Refineries and 
Changes Since Proposal

    As described in section II.B. of this preamble, we proposed, on 
January 6, 2012, Uniform Standards for Heat Exchange Systems as 40 CFR 
Part 65, subpart L and amendments to Refinery MACT 1 (40 CFR Part 63, 
subpart CC). We are not finalizing the Uniform Standards for Heat 
Exchange Systems at this time because we are still evaluating comments 
received on the March 26, 2012, proposed Uniform Standards for storage 
vessels, equipment leaks and closed vent system and control devices 
(see 77 FR 17898). We believe it is appropriate to consider all the 
comments received on the Uniform Standards proposed rules together, 
particularly since some of the comments received on the March 26, 2012, 
proposal relate to the overall concept and implementation of Uniform 
Standards across multiple industry categories. We are retaining in 
Refinery MACT 1 the substantive requirements for heat exchange systems. 
However, we are revising Refinery MACT 1 to incorporate many of the 
substantive changes in the work practice standards for heat exchange 
systems at petroleum refineries included in the Uniform Standards as 
part of the January 6, 2012, proposal.
    First, we are amending the definition of ``heat exchange system'' 
based on the proposed clarification of the definition and the public 
comments received. As proposed, we are replacing ``series of devices'' 
with ``collection of devices.'' In response to comments, we also are 
amending the definition of ``heat exchange system'' to improve clarity 
regarding the applicability of the monitoring and repair requirements 
for individual heat exchangers within the heat exchange system. 
Specifically, we are revising the definition of ``heat exchange 
system'' to focus on heat exchangers (and not sample coolers) that are 
in organic HAP service and that are associated with a petroleum 
refinery process unit. Therefore, we are finalizing the definition of 
``heat exchange system'' to mean a device or collection of devices used 
to transfer heat from process fluids to water without intentional 
direct contact of the process fluid with the water (i.e., non-contact 
heat exchanger) and to transport and/or cool the water in a closed-loop 
recirculation system (cooling tower system) or a once-through system 
(e.g., river or pond water). For closed-loop recirculation systems, the 
heat exchange system consists of a cooling tower, all petroleum 
refinery process unit heat exchangers that are in organic HAP service 
(as defined in this subpart) serviced by that cooling tower, and all 
water lines to and from these petroleum refinery process unit heat 
exchangers. For once-through systems, the heat exchange system consists 
of all heat

[[Page 37136]]

exchangers that are in organic HAP service (as defined in this subpart) 
servicing an individual petroleum refinery process unit and all water 
lines to and from these heat exchangers. Sample coolers or pump seal 
coolers are not considered heat exchangers for the purpose of this 
definition and are not part of the heat exchange system. Intentional 
direct contact with process fluids results in the formation of a 
wastewater.
    In the January 2012 proposal, we included clarifications of the 
sampling requirements and leak action level for once-through heat 
exchange systems when determining strippable hydrocarbon concentrations 
for the inlet water stream. We are finalizing these clarifications as 
proposed. After considering public comments, we are also revising the 
sampling requirement for once-through systems to allow monitoring at an 
aggregated location for once-through heat exchange systems, provided 
that the combined cooling water flow rate at the monitoring location 
does not exceed 40,000 gallons per minute.
    In the January 2012 proposal, we also proposed a direct water 
sampling and analysis option as an alternative to using the ``Air 
Stripping Method (Modified El Paso Method) for Determination of 
Volatile Organic Compound Emissions from Water Sources'' (Modified El 
Paso Method), Revision Number One, dated January 2003, Sampling 
Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 
2003 (incorporated by reference--see Sec.  63.14), as well as 
amendments to the recordkeeping and reporting requirements when this 
alternative is elected. After considering public comments, we are not 
revising Refinery MACT 1 to include this alternative.
    In the January 2012 proposal, we included an alternative monitoring 
frequency for heat exchange systems at existing sources. This 
monitoring frequency is quarterly using a leak action level defined as 
a total strippable hydrocarbon concentration (as methane) in the 
stripping gas of 3.1 ppmv; the only monitoring frequency in existing 
Refinery MACT 1 is monthly at a leak action level defined as a total 
strippable hydrocarbon concentration (as methane) in the stripping gas 
of 6.2 ppmv. We are revising Refinery MACT 1 to include the alternative 
monitoring frequency, as proposed.
    We proposed a clarification that the water flow rate could be 
determined based on direct measurement, pump curves, heat balance 
calculations or other engineering methods. We are finalizing this 
clarification as proposed. We also proposed clarifications to the 
applicability dates for heat exchange systems at new sources. We are 
finalizing these clarifications as proposed.
    The proposed Uniform Standards at 40 CFR 65.610(b) contained three 
exemptions: one based on pressure differential, one based on not being 
``in regulated material service,'' and one based on size (targeted to 
exclude sample coolers). As previously noted, we are not finalizing the 
Uniform Standards or the cross-references to those Uniform Standards 
from Refinery MACT 1. The corresponding section in Refinery MACT 1 (40 
CFR 63.654, Subpart CC) that we are finalizing in today's action 
contains only two exemptions: one based on pressure differential and 
one for intervening fluid. The exemptions for ``in HAP service'' and 
small heat exchangers are not needed based on the revised definition of 
``heat exchange system.'' These heat exchangers are not part of the 
affected heat exchange system as that term is defined in these final 
amendments.
    We are finalizing several technical and clarifying corrections in 
response to issues identified by public commenters. One of these 
amendments is in response to a commenter's request for clarity on how 
delay of repair emissions are to be calculated and for confirmation 
that the emissions should be estimated for the period of time that the 
delay of repair occurred. The October 2009 standards required the 
calculation of emissions projected for the ``expected duration of 
delay'' using the monitored leak concentration. As the heat exchange 
system for which repair is delayed must be monitored monthly, we 
interpret the rule to require a monthly estimate of the emissions 
projected for the duration of the delay of repair. However, the 
reporting requirement is an estimate of the emissions that occur as a 
result of delayed repairs over the reporting period. As such, the owner 
or operator must actually calculate the emissions projected over each 
monitoring interval and sum these estimates for the period covered by 
the semi-annual report. Therefore, in order to better align the 
calculation, recordkeeping and reporting requirements, we have revised 
the requirement to develop a monthly emission estimate for ``the 
duration of the expected delay of repair'' to require calculation of 
emissions projected for ``each monitoring interval.'' We also revised 
the recordkeeping requirements to keep records of these ``monitoring 
interval'' emission estimates, which can be directly used to develop 
the emission estimates required in the semi-annual reports. We are also 
clarifying that the delay begins on the date the leak would have had to 
be repaired had the repair not been delayed. We are revising the 
recordkeeping requirement for the ``identification of all heat 
exchangers at the facility'' to instead require records for 
``identification of all petroleum refinery process unit heat exchangers 
at the facility'' commensurate with our revision of the definition of 
``heat exchange system'' and our desire to focus the Refinery MACT 1 
heat exchange system requirements on heat exchangers associated with 
petroleum refinery process units. Finally, we are specifying that 
records related to the heat exchanger provisions be retained for 5 
years, consistent with retention requirements for other emissions 
sources.
    Today's final rule also addresses 10 reconsideration issues raised 
by the API. The API requested an administrative reconsideration under 
CAA section 307(d)(7)(B) of certain provisions of 40 CFR part 63, 
subpart CC that they had identified in an April 7, 2009, letter to the 
EPA. As described in detail in the January 6, 2012, proposal (see 77 FR 
964), we denied API's request for six of the reconsideration issues 
either because they were irrelevant after the subsequent withdrawal of 
the amendments to the Refinery MACT 1 storage vessel requirements or 
because the issues could have been raised during the public comment 
period. We granted reconsideration on the following issues: (1) The use 
of the promulgation date to describe the applicability for new sources 
in 40 CFR 63.640(h)(1); (2) the definition of ``heat exchange system'' 
in 40 CFR 63.641 as it relates to once-through heat exchange systems 
and refinery process units; (3) the monitoring procedures for once-
through heat exchange systems in 40 CFR 63.654(c); and (4) the 
determination of the cooling water flow rate in 40 CFR 63.654(g). This 
final action reflects our reconsideration of issues raised in API's 
request for reconsideration.

IV. Summary of Comments and Responses

A. Uniform Standards for Heat Exchange Systems

    On January 6, 2012, we proposed Uniform Standards for Heat Exchange 
Systems (40 CFR part 65, subpart L). We also proposed to remove most of 
the substantive requirements for heat exchange systems from Refinery 
MACT 1, to include them in the Uniform Standards, and to cross-
reference the Uniform Standards from Refinery

[[Page 37137]]

MACT 1. We received numerous comments on the creation of Uniform 
Standards for Heat Exchange Systems and the proposed cross-referencing 
to the Uniform Standards within Refinery MACT 1 (40 CFR part 63, 
subpart CC). We are not taking final action to create Uniform Standards 
for Heat Exchange Systems at this time. We will address the comments 
that focused on the creation of the Uniform Standards in the context of 
future Uniform Standards regulatory actions. Section IV.B of this 
preamble addresses the comments regarding the substance of requirements 
that we proposed to include in the Uniform Standards but that we are 
now finalizing as part of Refinery MACT 1, or requirements proposed in 
the Uniform Standards that we have decided not to finalize as they 
would apply to heat exchange systems at refineries.

B. Refinery MACT 1 Requirements for Heat Exchange Systems

1. Definition of Heat Exchange System
    Comment: One commenter supported the proposed change to the 
definition of ``heat exchange system'' that clarifies that heat 
exchangers need not be piped in series.
    Response: We appreciate support of this clarification.
    Comment: One commenter stated that including the cooling tower in 
the definition of ``heat exchange system'' means there can be only one 
heat exchange system per cooling tower, and this unduly complicates the 
rule (because the rule has to discuss requirements for individual 
exchangers and groups of exchangers as well as the heat exchange 
system). The commenter also suggested that the definition be limited to 
heat exchangers that serve petroleum refining process units to clarify 
that heat exchangers outside of the affected source are not subject to 
the Refinery MACT 1 requirements, which would be clearer than relying 
on the affected source description in 40 CFR 63.640 to limit 
applicability. Another commenter stated that monitoring provisions in 
40 CFR 63.654(a) should focus on heat exchangers that service refinery 
process units because there is no legal basis for applying the rule to 
heat exchangers that service non-refinery processes even if they share 
a cooling tower.
    Response: We disagree that including the cooling tower in the 
definition of heat exchange system creates confusion. Even if the 
cooling tower were not part of the heat exchange system, the regulatory 
language would still have to discuss heat exchangers, groups of heat 
exchangers and heat exchange systems to allow both centralized and 
separate monitoring of heat exchangers (or groups of heat exchangers). 
The flexibility provided in the monitoring locations, not the inclusion 
of the cooling tower, appears to be the primary source of complexity in 
the rule. As we allow monitoring of the cooling water at the cooling 
tower, it is logical that the cooling tower be part of the heat 
exchange system. Furthermore, the cooling tower is a central and 
essential part of a closed-loop heat exchange system for the system to 
operate properly. It is easily identifiable for permitting and 
enforcement personnel and it is the location at which most refineries 
are expected to perform the required monitoring. The cooling tower is 
also the location at which the strippable hydrocarbons are emitted.
    With respect to limiting the definition to heat exchangers that 
serve petroleum refining process units, we find that this comment has 
merit. Because Refinery MACT 1 is a NESHAP, in this final action, we 
intentionally limited repairs to heat exchangers that are ``in organic 
HAP service.'' The rule as finalized in 2009 also limited applicability 
by defining as part of the affected source ``all heat exchange systems 
associated with refinery process units and which are in organic HAP 
service'' in 40 CFR 63.640(c)(8). While we expect most heat exchange 
systems at petroleum refineries to process cooling water from heat 
exchangers associated only with refinery process units, we recognize 
that there may be other process units at a refinery, particularly 
ethylene units and units subject to the National Emission Standards for 
Organic Hazardous Air Pollutants from the Synthetic Organic Chemical 
Manufacturing Industry (40 CFR part 63, subpart F) (``HON'').
    We generally prefer not to include applicability criteria in 
emission source definitions, but recognizing the complexity of the 
current construct, we considered whether revising the definition of 
heat exchange system might increase the clarity of the monitoring and 
repair requirements for specific heat exchangers within the heat 
exchange system. Specifically, we considered defining a closed-loop 
heat exchange system as ``a cooling tower, all petroleum refinery 
process unit heat exchangers serviced by that cooling tower that are in 
organic HAP service, as defined in this subpart, and all water lines to 
and from these petroleum refinery process unit heat exchangers.'' The 
qualifications in this definition provide clarity that the repair 
requirements in 40 CFR 63.654 apply only to refinery process unit heat 
exchangers that are in organic HAP service; other heat exchangers that 
might be serviced by a common cooling tower are not part of the ``heat 
exchange system.'' A similar revision for once-through systems would be 
``all heat exchangers that are in organic HAP service, as defined in 
this subpart, servicing an individual petroleum refinery process unit 
and all water lines to and from these heat exchangers.'' Considering 
the broad definition of ``petroleum refinery process unit'' and the 
existing exclusions in 40 CFR 63.640(g), we are finalizing these 
revisions to the definition of heat exchange system because we believe 
that these revisions clarify the intent of the requirements within 
Refinery MACT 1 as finalized in October 2009 and limit the 
applicability of the repair requirements to individual heat exchangers 
servicing refinery process units.
    Comment: Two commenters suggested that all sample coolers and pump 
seal coolers should be specifically exempted from the monitoring 
requirements and/or that the threshold in 40 CFR 65.610(b)(3) should be 
raised from 10 gallons per minute to 50 gallons per minute. The 
commenters stated that it was burdensome to have to evaluate the flow 
rate for every sample cooler at the refinery in order to assess the 
monitoring applicability and that sample coolers were not considered in 
the EPA analysis of heat exchange systems.
    Response: In the January 2012 proposal, we included an exemption 
for very small heat exchange systems (those with water flow rates less 
than 10 gallons per minute). This exemption was specifically targeted 
to exempt sample coolers and pump seal coolers because we did not 
consider these coolers significant sources of emissions and did not 
include them in our MACT floor and impacts analysis for the October 
2009 final rule. We considered providing a higher flow exclusion to 
individual heat exchangers, but this would still require the refinery 
owners and operators to identify and assess the flow rates of each 
sample cooler. After reviewing the options, we have concluded that 
adding language to specifically exclude sample coolers and pump seal 
coolers from the definition of heat exchange system provides the 
clearest means to ensure that the regulations do not unintentionally 
capture these ``coolers'' that were not considered part of a ``heat 
exchange system'' in our original analysis and that we did not intend 
to be monitored under the Refinery MACT 1 regulations.

[[Page 37138]]

See the new regulatory definition at 40 CFR 63.641 for heat exchange 
system.
    Comment: One commenter suggested that the EPA define the term 
``strippable hydrocarbons'' to mean the hydrocarbons measured by any of 
the methods specified in 40 CFR 65.610(a)(3).
    Response: We considered providing a specific definition of 
``strippable hydrocarbons'' in these final amendments, but the 
suggested definition is unnecessary since we are not finalizing the use 
of water methods as an alternative monitoring method for petroleum 
refineries. The monitoring method required by the regulations, the 
Modified El Paso Method, provides the best definition of strippable 
hydrocarbons as it relates to potential emissions from heat exchange 
systems.
2. Applicability and Exemptions
    Comment: One commenter supported the proposed revisions clarifying 
the construction date criteria for defining a new source for the 
purpose of the heat exchange provisions.
    Response: We appreciate support of this clarification.
    Comment: One commenter recommended deleting the provision that 
limits once-through heat exchange systems to a single process unit 
because the MACT floor analysis does not support this approach. 
Although the process unit restriction is currently in 40 CFR 63.641, 
the commenter noted that this language was not in the September 4, 
2007, proposal or the November 10, 2008, supplemental proposal and, 
therefore, has not been subject to public comment until now. The 
commenter stated that, if the process unit restriction is maintained, 
the EPA should limit the rule to monitoring systems with a flow greater 
than 5,000 gallons per minute because the EPA's analysis shows control 
for smaller systems is not cost effective. The commenter also suggested 
that the EPA's analysis did not consider monitoring once-through 
systems individually.
    Response: Although the original MACT floor and impacts analysis 
(see the technical memorandum titled, ``Cooling Towers: Control 
Alternatives and Impact Estimates,'' Docket Item No. EPA-HQ-OAR-2003-
0146-0143) referred to ``cooling towers'' rather than ``heat exchange 
systems,'' we believe the analysis adequately considered all heat 
exchange systems at all petroleum refineries. We projected the 
nationwide total number of ``cooling towers'' to be 520 using 
information from the Texas Commission on Environmental Quality (TCEQ) 
for 50 petroleum refineries and extrapolating (considering capacity) to 
all U.S. petroleum refineries. Based on this analysis, every refinery 
was projected to have several ``cooling towers'' or ``heat exchange 
systems'' in our MACT floor and impacts analysis, and we assumed that 
refineries with once-through cooling systems would have a similar 
number of heat exchange systems (per refining capacity) as refineries 
with closed-loop (cooling tower) systems. We conducted analyses to 
determine how the number of cooling towers or heat exchange systems 
would affect our MACT floor calculations if there were more than our 
estimated 520. Because the monitoring and repair requirements for many 
of the best-performing heat exchange systems were identical, we 
determined that the MACT floor requirements for existing sources would 
be the same even if there were as many as 666 affected ``cooling 
towers'' or ``heat exchange systems'' (see the technical memorandum 
titled, ``Revised Impacts for Heat Exchange Systems at Petroleum 
Refineries,'' Docket Item No. EPA-HQ-OAR-2003-0146-0230).
    To further verify our MACT floor calculations, we reviewed the 
information collected during the detailed information collection 
request (ICR) for petroleum refineries (see Docket Item Nos. EPA-HQ-
OAR-2010-0682-0061 through 0069). The definition for heat exchange 
system in the ICR was identical to the definition in Refinery MACT 1 
(with once-though systems limited to individual process units). Based 
on the ICR responses, there are 525 heat exchange systems that are in 
organic HAP service and that do not qualify for the exemption from 
monitoring based on higher water-side pressures; only 21 of these 525 
are once-through heat exchange systems. We note that there are 50 
additional closed-loop heat exchange systems for which respondents did 
not answer these ``applicability'' questions, so we project that the 
total number of affected heat exchange systems is somewhat more than 
525 but less than 575. Therefore, our estimate of 520 affected heat 
exchange systems (including once-through systems) was reasonably 
accurate, and the existing source MACT floor monitoring requirements 
would not be impacted had we used the upper range estimate from the ICR 
data. As such, we disagree that our MACT floor analysis is inconsistent 
with the restriction of once-through systems to a single process unit.
    With respect to the suggestion that we limit the monitoring of 
closed-loop heat exchange systems to only those with flows of 5,000 
gallons per minute or more, we note that closed-loop heat exchange 
systems that have flow rates less than 5,000 gallons per minute are 
common at refineries. These smaller heat exchange systems were included 
in our MACT floor and impacts analysis, and we did not subcategorize 
these heat exchange systems by size. The assertion that monitoring 
these smaller heat exchange systems is not cost effective is not 
relevant; we do not consider costs in developing the MACT floor 
requirements. We only consider costs when evaluating alternatives 
beyond the MACT floor. As described previously, we believe we 
adequately considered the total number of affected heat exchange 
systems (including once-through and small heat exchange systems) when 
establishing the MACT floor requirements for existing sources.
    We noted in the January 2012 proposal that: ``A once-through heat 
exchange system could include all heat exchangers at the entire 
facility. The potential to aggregate all cooling water at a facility 
(as opposed to a single process unit) prior to sampling for a once-
through system would greatly reduce the effectiveness of the leak 
monitoring methods and would allow HAP or VOC leaks to remain 
undetected, based solely on the dilution effect from the vast quantity 
of water processed at the facility.'' (See 77 FR 967). We specifically 
requested comment on how we might allow some aggregation across units 
but not allow dilution across all units at the plant. The commenter did 
not provide any suggestions on this point, but rather suggested that if 
aggregation were not allowed, once-through heat exchange systems with 
flow less than 5,000 gallons per minute should be excluded.
    For closed-loop heat exchange systems, there are physical 
limitations on the cooling tower that limit the number of units that 
can be serviced by the cooling tower. Again, our analysis suggested 
there would be several heat exchange systems per refinery compared to a 
single heat exchange system for once-through systems. On the other 
hand, we recognize that the definition of ``heat exchange system'' in 
the October 2009 final rule limits aggregation for refineries operating 
once-through systems more than refineries that operate closed-loop 
systems. Therefore, we evaluated several ways to afford some 
aggregation for once-through heat exchange systems so that these 
systems would be more comparable to the ``cooling tower'' heat exchange 
systems identified in the MACT floor memorandum (Docket Item No. EPA-
HQ-OAR-2003-0146-0143). We identified no appropriate way to allow some, 
but constrained aggregation

[[Page 37139]]

across process units within the definition of heat exchange system. 
Therefore, we are not modifying the definition of ``heat exchange 
system'' as it relates to once-through systems (i.e., a once-through 
heat exchange system is still limited to the heat exchangers associated 
with a single refinery process unit). As an alternative, we evaluated 
allowing monitoring for once-through cooling systems at locations that 
include cooling water from several heat exchange systems. Based on the 
responses from the detailed ICR, approximately 90 percent of all 
cooling towers (i.e., closed-loop heat exchange systems) at petroleum 
refineries have flow rates of 40,000 gallons per minute or less. As 
such, we consider that this 90th percentile value provides a reasonable 
proxy of the upper level of aggregation provided to facilities with 
closed-loop heat exchange systems. By allowing once-through heat 
exchange systems to monitor at locations that include cooling water 
from several heat exchange systems, provided that the combined cooling 
water flow rate at the monitoring location does not exceed 40,000 
gallons per minute, we are providing a means to aggregate across 
process units in a manner similar to that afforded to closed-loop heat 
exchange systems, which is the assumption made in our MACT floor and 
impacts analyses. As this level of aggregation is similar to that for 
closed-loop heat exchange systems, we expect that this provision will 
achieve the same emission reductions at the same costs as projected for 
our model closed-loop heat exchange systems. We also note that this 
approach is preferable to the suggested exemption for all once-through 
heat exchange systems below 5,000 gallons per minute because it 
achieves greater emission reductions at similar costs. Therefore, we 
have amended the monitoring location for once-through heat exchange 
systems to allow monitoring at a point where discharges from multiple 
heat exchange systems are combined, provided that the combined cooling 
water flow rate at the monitoring location does not exceed 40,000 
gallons per minute.
    Comment: Several commenters stated that the EPA should retain the 
exemption for heat exchange systems that have an intervening cooling 
fluid that contains less than 5 percent by weight of HAP.
    Response: This exemption was included in the October 2009 final 
standards for refinery heat exchange systems and it was our intent to 
retain this existing exemption for petroleum refineries. However, when 
the heat exchange system Uniform Standards were proposed, we 
inadvertently omitted a cross-reference to this exemption from Refinery 
MACT 1. As noted previously, we are not promulgating the Uniform 
Standards or the cross-references to the Uniform Standards from 
Refinery MACT 1. The provision to exempt heat exchange systems that use 
an intervening fluid that is less than 5 percent by weight HAP is 
retained as a part of Refinery MACT 1.
    Comment: One commenter suggested that the introductory paragraph in 
40 CFR 65.610(b) should specify that engineering judgment may be used 
to determine whether any of the exemption criteria are met.
    Response: As noted in section III of this preamble, heat exchangers 
may be excluded from a ``heat exchange system'' based on differential 
pressure or the presence and content of an intervening fluid. We did 
not specify that engineering judgment can be used for the differential 
pressure exemption, either in the October 2009 final rule or the 
January 2012 proposed amendments. We expect that direct pressure 
measurements of the process fluids and cooling water lines will be made 
in a representative location at which the pressure exclusion can be 
documented. With respect to the intervening fluid exemption, we 
intended that the same requirements used to determine ``in organic HAP 
service'' would apply to the intervening fluid. We revised the 
description of this exemption to specify that the provisions of 40 CFR 
63.180(d) of subpart H should be used; 40 CFR 63.180(d) allows the use 
of ``good engineering judgment'' under most circumstances.
3. Compliance Date
    Comment: One commenter suggested that the compliance date be reset 
to be at least 1 year after the promulgation date of the final 
amendments to provide time for the refineries to develop procedures for 
complying with the proposed options and any other changes made in 
response to public comments.
    Response: Petroleum refinery owners and operators have been on 
notice of the October 29, 2012, compliance date since promulgation of 
the heat exchange standards in October 2009. Refinery owners and 
operators that follow the requirements in the October 2009 final rule 
will be in compliance with these final amendments. If a facility elects 
to change to quarterly monitoring at the lower leak definition, there 
are provisions in the final amendments for how this change can be made. 
Therefore, there is no need to reset the compliance date.
4. Monitoring Locations and Analytical Methods
    Comment: Several commenters requested that a leak be determined 
based on the difference between inlet and outlet concentrations. One 
commenter specifically noted that the EPA should reconsider this 
approach, which is used in the Hazardous Organic NESHAP (``HON''; 40 
CFR part 63 subpart F), for refinery heat exchange systems. The 
commenter disputed the EPA claims that accumulating hydrocarbons in the 
cooling water are evidence of a leak and that small leaks are cost 
effective to repair, stating the build-up of organic chemicals can be 
caused by the use of chemical additives for corrosion or biological 
growth prevention and these heavy compounds are not stripped in the 
cooling tower as completely as they are in the Modified El Paso Method 
stripping column.
    Response: The rule does not provide for the use of inlet and outlet 
sampling for closed-loop heat exchange systems because the MACT floor 
requirements for heat exchange systems were based on existing 
monitoring of the cooling water return line only. If the rule allowed 
the use of a concentration differential, it would be less stringent 
than the MACT floor because the MACT floor monitoring was not based on 
a differential concentration, but the direct concentration in the 
cooling water return line. Although we expect that the strippable 
hydrocarbons measured by the Modified El Paso Method will be largely 
removed (i.e., released to the air) in the cooling tower so that the 
cooling water inlet to the heat exchangers will have limited 
concentrations of strippable hydrocarbons, it is unlikely that this 
concentration would be exactly zero. Therefore, using a concentration 
differential produces a concentration that has been adjusted to account 
for hydrocarbons still in the water after the cooling tower, and is 
lower and therefore less likely to trigger the leak definition. We did 
not allow this option for closed-loop heat exchangers. The rule does 
provide for the use of inlet and outlet sampling for once-through heat 
exchange systems. While we have taken the position that once-through 
heat exchange systems have a similar emission potential as closed-loop 
systems, we acknowledge that these systems are different in operation 
and that contaminants may be present in the pond, river or other source 
of once-through cooling water that is beyond the control of the 
refinery owner or operator and that will not be ``pre-stripped'' in a 
cooling tower. Therefore, we conclude that it is reasonable and 
necessary to

[[Page 37140]]

allow a concentration differential to be used to determine a leak for 
once-through heat exchange systems.
    Comment: One commenter noted that the requirements in 40 CFR 
65.610(e) are unnecessarily burdensome because they require a source to 
monitor all heat exchangers to find a leak and they appear to require 
continued monthly testing of all heat exchangers even if the leak is 
not from an exchanger that is subject to the repair requirements. This 
commenter also recommended simply requiring the leaking exchanger to be 
identified by the most expeditious process and then requiring repair 
only if the leaking exchanger is in service associated with a 
referencing subpart.
    Response: The cited provisions do not require monitoring of all 
affected heat exchangers to find a leak. The refinery owner or operator 
can use any method they choose to identify the leaking heat exchanger. 
If the identified leaking heat exchanger is not in HAP service, then 
the refinery owner or operator has two options: (1) fix the leak and 
continue to monitor in the main cooling tower return line or (2) 
demonstrate that all heat exchangers within the heat exchange system 
that are subject to the monitoring and repair provisions are not 
leaking by monitoring each heat exchanger or group of heat exchangers 
subject to the repair provisions. Thus, the option of monitoring each 
heat exchanger or group of heat exchangers is not required to identify 
the leaking heat exchanger; rather, this monitoring option is provided 
only for the case in which the refinery owner or operator elects not to 
fix a leak that was identified through monitoring of the cooling tower 
return line on the grounds that the leaking heat exchanger is not 
subject to the repair provisions in Refinery MACT 1.
    Comment: One commenter suggested that the monitoring frequency/leak 
definition alternatives for existing sources should be allowed on an 
individual or group of heat exchangers basis as well as on a heat 
exchange system basis.
    Response: The rule allows monitoring at the individual heat 
exchanger (or group of heat exchangers) level or at the heat exchange 
system level (i.e., monitoring at the cooling tower). However, in order 
to allow this flexibility for either aggregate or individual monitoring 
to be performed without any notification to the EPA, all heat 
exchangers that are part of a heat exchange system must use the same 
monitoring frequency and leak definition. We considered allowing the 
suggested alternative for individual heat exchangers within a heat 
exchange system, but concluded that it would likely result in 
uncertainty regarding what compliance monitoring, reporting and 
recordkeeping requirements would be required for individual heat 
exchangers. As the affected facility is the heat exchange system, we 
consider it appropriate that the same monitoring frequency and leak 
definition be used for all monitoring locations within one heat 
exchange system. The final rule clearly allows (in 40 CFR 63.654(c)(4)) 
the owner or operator of existing sources to use the alternative 
quarterly monitoring option for some heat exchange systems and the 
monthly monitoring option for others but all heat exchangers or groups 
of heat exchangers within a single heat exchange system must use the 
same monitoring frequency and leak definition.
    Comment: Two commenters noted that section 5.1.1.4 of the Modified 
El Paso Method specifies that samples must be drawn from a location 
prior to the risers. The commenter requested clarification that 
monitoring may instead be conducted either prior to the risers or in 
any individual riser because the concentration of hydrocarbons is 
distributed equally to each riser and the system has no openings to the 
atmosphere prior to discharge into the cooling tower cells. They also 
noted that refineries often monitor in a riser and changes needed to 
enable monitoring prior to the riser would require a significant 
capital expenditure.
    Response: The final amendments describe monitoring locations 
specific for Refinery MACT 1 and then separately describes the allowed 
monitoring methods. Reference to the Modified El Paso Method is 
confined to the monitoring method section of Refinery MACT 1, and the 
Modified El Paso Method's restriction on sampling in the riser is not 
applicable. Nonetheless, we have provided specific clarifications in 
the monitoring location section that monitoring in the cooling tower 
riser (prior to exposure to the atmosphere) is allowed.
    Comment: One commenter stated that, in addition to a flame 
ionization detector, the EPA should allow use of other detectors, such 
as a photo ionization detector or mass spectrometry and online gas 
chromatograph (GC) capable of equivalent sensitivity for target 
compounds when using the Modified El Paso Method.
    Response: We specifically require the stripping gas concentration 
to be determined in ppmv as methane. While a refinery owner or operator 
may elect to use a GC and other analyzers to speciate the compounds 
present in the cooling water in order to identify the specific heat 
exchangers or group of heat exchangers responsible for the leak, the 
leak itself must be determined using a flame ionization detector 
calibrated with methane following the procedures in section 6.1 of the 
Modified El Paso Method. As discussed in further detail in the 
following comment and response, we find that speciated analysis of 
target compounds in the stripping gas is likely to result in incomplete 
characterization of the total hydrocarbon concentration and could be 
less stringent than the MACT floor determined for petroleum refinery 
heat exchange systems. We have further clarified this requirement in 
these final amendments by specifically referencing section 6.1 of the 
Modified El Paso Method. However, this requirement does not preclude 
the refinery owner or operator from conducting additional analysis of 
the stripping gas as a means to identify the leaking heat exchanger.
    Comment: Several commenters requested that the rule allow 
additional measurement methods in order to characterize the compounds 
that could leak into the cooling water. The measurement methods 
suggested include EPA Method 624 of Appendix A to 40 CFR part 136 and 
SW-846 Methods 8270 and 8315. Commenters also stated that 
characterizing all volatile compounds (or even all volatile organic 
HAP) is often impossible due to the high number of compounds that may 
be in a process stream, and it is not necessary, as detection of key 
compounds from the process is all that is needed to identify a leak. 
One commenter suggested that this rule should be like the TCEQ's rule 
that requires characterization of compounds with boiling points less 
than 140 degrees Fahrenheit ([deg]F). This commenter recommended 
allowing any measurement method that is sensitive to at least 90 
percent of the species with boiling points less than 140[emsp14][deg]F, 
and allowing subtraction of compounds with boiling points greater than 
140[emsp14][deg]F from the ``total strippable hydrocarbon'' 
concentration. Several commenters recommended including a general 
procedure for monitoring surrogate species or indicator species rather 
than requiring full speciation. For example, one commenter requested 
that the rule allow the analysis to focus on one compound that the 
method easily detects and then estimate the total strippable 
hydrocarbon concentration assuming the ratio of that compound to all 
organic compounds in the cooling water is the same as in the process 
fluid.
    Response: We acknowledge the difficulty characterizing all 
compounds

[[Page 37141]]

in a petroleum refinery process stream. While we considered including 
additional test methods, the inclusion of additional test methods did 
not appear to address the primary issue regarding the ability to fully 
characterize the compounds that could leak into the cooling water. We 
disagree that the characterization of compounds should be limited to 
compounds with boiling points less than 140[emsp14][deg]F. Hexane, 
benzene and toluene all have boiling points above 140[emsp14][deg]F; 
these compounds are expected to be emitted from heat exchange systems 
and are expected to be detectable using the Modified El Paso Method. 
The Modified El Paso Method was designed to have high (99 percent or 
higher) recovery of compounds with boiling points below 
140[emsp14][deg]F and avoids potential losses of highly volatile 
compounds associated with direct water sampling methods. For this 
reason, while the Modified El Paso Method is required to be used by the 
TCEQ for cooling tower sampling when pollutants have boiling points 
below 140[emsp14][deg]F, it is incorrect to conclude that the Modified 
El Paso Method will not measure any compounds with boiling points 
greater than 140[emsp14][deg]F.
    Since the data used to establish the MACT floor were based on the 
Modified El Paso Method, in order to be at least as stringent as the 
MACT floor, any alternative monitoring option provided in the rule must 
be as effective as the El Paso Method in detecting the HAP that are 
indicative of a leak. Limiting the direct water method analysis only to 
compounds with boiling points less than 140[emsp14][deg]F would be less 
stringent than the Modified El Paso Method and thus we disagree with 
the commenter that direct water methods should be provided as an 
option.
    In the proposed Heat Exchanger Uniform Standards, we proposed to 
allow the use of a water method that would identify all leaked 
compounds as an alternative monitoring method. Our intent was for this 
approach to be used where a heat exchanger cooled a process fluid that 
contained a very limited number of compounds. We expected that very 
few, if any, petroleum refinery heat exchange systems would choose to 
use the water methods for most heat exchangers, given the requirement 
to fully characterize all compounds that could leak into the cooling 
water.
    The proposed water methods were expected to be at least as 
stringent as the Modified El Paso Method because the requirement to 
fully characterize the pollutants that could leak into the wastewater 
would include all compounds, even those that may not be effectively 
stripped in the stripping column (or cooling tower). Options to limit 
the full characterization requirement call into question the ability of 
the water methods to be as stringent as the total strippable 
hydrocarbon analysis using the Modified El Paso Method.
    In light of the complexity of most petroleum refinery process 
streams, we are concerned that there may be a leak that exceeds 40 
parts per billion by weight (ppbw) total strippable hydrocarbons in the 
water-phase as determined by back-calculation from the Modified El Paso 
Method results, but because of the number of different compounds 
present in the petroleum refinery stream (often on the order of 50 to 
100 different compounds), the concentrations of the individual 
compounds could all be below the analytical detection limit (typically 
about 5 to 10 ppbw in the cooling water). In such a case, the water 
methods, even with low detection limits, may not provide a suitable 
alternative to the Modified El Paso Method for refinery heat exchange 
systems.
    To further evaluate our concerns regarding the use of water 
measurement methods for refinery heat exchange systems, we reviewed the 
source test data received in response to the cooling water testing 
required as part of the detailed information collection request for 
petroleum refineries. We compared the stripping column gas sampling 
results with those from the direct water methods (see the memorandum 
titled, ``Evaluation of the Refinery ICR Cooling Water Analysis 
Results'' in Docket ID No. EPA-HQ-OAR-2003-0146). We found that the 
analytical methods for chemical species (in both stripping gas analysis 
and water samples) greatly underestimated the overall concentrations of 
hydrocarbons, primarily because these analyses were conducted using a 
specific target analyte list. As the water methods (or gas-phase 
speciated analysis methods) generally include a specific list of target 
analytes, we now expect that these methods could lead to less effective 
leak identification.
    We considered the alternative of monitoring a specific compound and 
extrapolating that compound concentration to determine a total 
strippable hydrocarbon concentration, but we determined that this 
approach generally would be more complicated and burdensome than direct 
Modified El Paso monitoring, given the complexity of petroleum refinery 
process fluids and the likelihood that several different heat 
exchangers (with process fluids of differing compositions) may be 
serviced by a single cooling tower (i.e., heat exchange system). We see 
no easy way to specify ``a general procedure for monitoring surrogate 
species or indicator species'' while ensuring equivalency with the 
Modified El Paso Method. One would need to use the Modified El Paso 
Method to develop the extrapolation factor for each process fluid that 
could potentially leak into the cooling water and to verify that the 
method used provides adequate detection limits. This would be difficult 
to do and complex, considering the potential variation in compounds and 
concentrations across process streams.
    Given the complexity of most petroleum refinery process streams, we 
were unable to identify from the currently available water methods a 
method that would be suitable for determining the total strippable 
hydrocarbon concentration with the accuracy and sensitivity needed to 
be comparable to the Modified El Paso Method. Therefore, we are not 
finalizing any alternative water methods for monitoring petroleum 
refinery heat exchange systems.
    Comment: Several commenters requested that the rule allow 
measurement of surrogates. One commenter requested inclusion of the 
full spectrum of monitoring methods currently listed in the HON, the 
National Emission Standards For Ethylene Manufacturing Process Units: 
Heat Exchange Systems And Waste Operations (40 CFR part 63, subpart XX) 
(``Ethylene NESHAP''), and the online monitoring for ethylene and 
propylene that is allowed in TCEQ HRVOC Rule (TAC Title 30 Part I 
Chapter 115 Div. 2 Sec.  115.764). One commenter noted that the 
proposed methods would require most facilities to use offsite test 
resources, but other methods, particularly if surrogates can be 
measured, would allow sites to conduct analyses themselves and respond 
more quickly to any leaks.
    Response: We disagree with the comments suggesting all measurement 
methods provided in the HON, the Ethylene NESHAP or the TCEQ rules 
should be allowed. The leak definition for petroleum refineries is 
lower than specified in those rules. In our revised impacts analysis 
for the proposed amendments(see the technical memorandum titled, 
``Revised Impacts for Heat Exchange Systems at Petroleum Refineries,'' 
Docket Item No. EPA-HQ-OAR-2003-0146-0230), the leak detection level 
was generally the most important parameter influencing the 
effectiveness of the heat exchange system monitoring program. We 
evaluated a series of ``surrogate''

[[Page 37142]]

methods when evaluating different heat exchange system monitoring 
alternatives for the October 2009 final rule and concluded that these 
surrogate methods were not as effective as identifying leaks as the 
Modified El Paso Method.
    We acknowledge that the proposed water method alternatives would 
often require the use of external laboratories; however, as discussed 
previously, we are not finalizing the proposed water method 
alternatives. The Modified El Paso Method, on the other hand, is 
performed on-site. The method is relatively simple and can be operated 
by refinery personnel or outside contractors to provide immediate leak 
monitoring results, so it has the same advantages of the ``surrogate'' 
methods while also being able to detect small leaks.
    Comment: One commenter requested that sources be allowed up to 7 
calendar days for re-monitoring a heat exchange system to verify repair 
when a repaired heat exchanger is returned to service either after the 
end of the 45-day normal repair window (as long as the heat exchanger 
was taken out of service before the end of that 45-day window) or after 
an allowed delay of repair period. The commenter noted that if the heat 
exchanger is taken out of service as the means of repair and then 
brought back into service after the 45-day window, then additional time 
is needed to start up, line-out, and retest that heat exchanger.
    Response: In the January 2012 proposal, we proposed to clarify that 
under the existing MACT standard, ``repair'' includes verification that 
the actions taken to repair the leak were effective through re-
monitoring of the heat exchange system. We consider the 45-day repair 
window for a typical repair as well as the additional time provided for 
a delayed repair to be adequate considering the time necessary to re-
monitor the heat exchange system. We expect that repairs will be made 
as expeditiously as possible and that the actions will be taken with 
sufficient time to confirm the repairs within the 45-day repair window. 
Refinery MACT 1 specifically allows the use of removing a heat 
exchanger from service as a means to effect repair in 40 CFR 
63.654(d)(5). The heat exchange system would need to be re-monitored 
within the 45-day window to verify that the removal of the heat 
exchanger effectively reduced the total hydrocarbons in the cooling 
water to below the leak threshold levels. In this case, the removal of 
the heat exchanger from service would accomplish the repair and the 
owner or operator could revert back to their chosen monitoring 
frequency.
    The rule is silent on a special monitoring event for the case in 
which the removed heat exchanger is subsequently placed back into 
service. This case is similar to the case where a new heat exchanger 
(or group of heat exchangers) is added to an existing heat exchange 
system. We interpret the rule to require only the routine heat exchange 
system monitoring with no special monitoring event required when adding 
these ``new'' heat exchangers to the heat exchange system. We 
anticipate that any ``new'' or ``repaired'' heat exchanger would be 
properly pressure tested prior to being placed in service. As such, 
these heat exchangers would be unlikely to leak, so the routine 
monitoring frequency is considered sufficient. We also note that, if an 
owner or operator removes a heat exchanger from service as a means to 
effect a repair, but then returns the same heat exchanger to service 
without any modification or repair, that owner or operator could be 
subject to potential enforcement actions for not complying with the 
operating and maintenance requirement ``. . . to maintain any affected 
source . . . in a manner consistent with safety and good air pollution 
control practices for minimizing emissions'' as required in the General 
Provisions at 40 CFR 63.6(e).
5. Delay of Repair
    Comment: One commenter suggested allowing delay of repair until the 
next scheduled process shutdown if the source opts to strip hydrocarbon 
from the cooling water and either recover it (as fuel or for process 
use) or collect and convey it to combustion control.
    Response: Provided that the stripped gases are properly captured 
and controlled, the current provisions would not exclude these actions 
as a means of compliance. The rule only lists those repair actions that 
are most likely to occur but we explicitly indicate that the list of 
repair actions is not all inclusive. If the actions described by the 
commenter reduce the concentration of strippable hydrocarbons to below 
the applicable leak action levels while preventing the release of those 
hydrocarbons to the atmosphere, we consider that these actions qualify 
under 40 CFR 63.654(d) as a repair, in which case the delay of repair 
would not be needed.
    If the actions described by the commenter do not reduce the 
strippable hydrocarbon concentration to below the leak action level, 
the existing delay of repair provisions, if applicable, can be used to 
continue operating until the next scheduled shutdown. In this case, the 
actions described by the commenter could be used to help prevent an 
exceedance of the delay of repair action level and thereby maintain the 
delayed repair. However, if the leak ever exceeds the delay of repair 
action level, the owner or operator could not use these actions merely 
to reduce the strippable concentration to below the delay of repair 
action level. Once the delay of repair threshold is exceeded, the owner 
or operator of the affected heat exchange system must repair the source 
within 30 days by reducing the strippable hydrocarbon concentration to 
below the leak action level.
    Comment: One commenter requested confirmation that the guidelines 
given in TCEQ's Sampling Procedures Manual, Appendix P, paragraph 7.2 
should be used for determining the molecular weight to use in equation 
7.1 of the Modified El Paso Method when determining potential emissions 
during a delayed repair.
    Response: The TCEQ's Sampling Procedures Manual, Appendix P, is the 
Modified El Paso Method that is incorporated by reference in the heat 
exchange system provisions of Refinery MACT 1. In 40 CFR 63.654(g)(4), 
we specifically indicate that the stripping air concentration must be 
converted to a water concentration using Equation 7-1 of the Modified 
El Paso Method. Paragraph 7.2 of the Modified El Paso Method 
specifically notes that ``[f]or total VOC based on the portable FID 
analyzer procedure in Section 6.1, calculate total VOC concentration in 
the water and emission rate based on the molecular weight of methane . 
. .'' We specifically require the use of the stripping gas 
concentration to be determined using flame ionization detector (FID), 
as noted in section 6.1 of the Modified El Paso Method, calibrated with 
methane (``as methane''). Therefore, the molecular weight of methane 
(16 grams per mole) should be used when determining the equivalent 
water concentration using Equation 7-1 of the Modified El Paso Method 
when calculating the potential strippable hydrocarbon emissions for a 
delayed repair. We have clarified this requirement in these final 
standards.
6. Reporting and Recordkeeping Provisions
    Comment: One commenter requested clarification that the requirement 
to record water flow rates applies only to monitoring events in which a 
leak is detected and the equipment is placed on delay of repair because 
this is the only occasion in which flow rates are

[[Page 37143]]

needed. Another commenter stated that records of water flow and 
emissions estimates should be required only if the rule allows delay of 
repair based on a demonstration that the emissions caused by delaying 
repair are less than the emissions caused by a process unit shutdown, 
if needed, to effect the repair because this is the only situation 
where water flow and emissions are relevant. If these requirements are 
not deleted, one of the commenters stated that the EPA should clarify 
that the recordkeeping requirement is an estimate of ``potential 
strippable hydrocarbon emissions'' instead of ``potential emissions'' 
because the latter might be misinterpreted to mean organic HAP 
emissions, which are only a fraction of the hydrocarbon emissions. In 
addition, a commenter stated that the EPA should clarify that reporting 
of ``an estimate of total strippable hydrocarbon emissions for each 
delayed repair over the reporting period'' covers only the time period 
from the date by which repair would have had to be completed if it were 
not delayed until the repair was completed.
    Response: The October 2009 final rule requires a record of the 
cooling water flow rate for each monitoring event. However, the 
commenter correctly notes that the requirement in 40 CFR 
63.654(g)(4)(ii) to determine the flow rate of cooling water only 
applies during periods in which repair is delayed. As such, we agree 
with the commenter that the regulations should not require records of 
the cooling water flow rate for all cooling towers or heat exchangers 
because the flow rate only needs to be determined for heat exchange 
systems for which repair is delayed. Therefore, we are moving the 
requirement to keep a record of the cooling water flow rate to the 
paragraph that is limited to delayed repairs, which is 40 CFR 
63.655(i)(4)(v) in today's final rule.
    We disagree that recordkeeping and reporting of flow rate and 
potential emissions should only be required where emission caused by 
delay of repair are demonstrated to be less than they otherwise would 
be during a shutdown. Stakeholders including the public should be made 
aware of the potential air emissions releases that may occur based on 
the decision to delay repair.
    We agree that the phase ``potential strippable hydrocarbon 
emissions'' more accurately describes the delay of repair emission 
estimate than the phrase ``potential emissions'' and we are clarifying 
the language as suggested by the commenter. Specifically, we are 
revising ``potential emissions'' to instead read ``potential strippable 
hydrocarbon emissions'' in the heat exchange system requirements at 40 
CFR 63.654(g)(4), the reporting requirements at 40 CFR 63.655(g)(9)(v) 
and the recordkeeping requirements at 40 CFR 63.655(i)(4)(v) in today's 
final rule.
    As described previously in section III of this preamble, today's 
final rule requires that these emission estimates be determined for 
each monitoring interval instead of over the ``expected duration of the 
delay.'' To address the commenter's concern, we are specifying in 40 
CFR 63.654(g)(4)(iii) that ``The duration of the delay of repair 
monitoring interval is the time period starting at midnight of the day 
of the previous monitoring event or midnight of the day the repair 
would have had to be completed if the repair had not been delayed, 
whichever is later, . . .'' Given this clarification in the start of 
the delay of repair interval and the coordination between the emission 
estimate methodology and reporting requirements, we do not believe that 
additional language is needed in 40 CFR 63.655(g)(9)(v) to further 
clarify that the delay of repair starts at the end of the 45-day period 
provided to complete a repair under normal circumstances.
    Comment: One commenter requested clarification of the term 
``original date'' in the reporting requirements in 40 CFR 
63.655(g)(9)(v) for delayed repair.
    Response: We are clarifying this regulatory provision by revising 
the phrase ``original date'' to instead say ``date when the delay of 
repair began.'' As noted in the clarified language regarding the 
calculation of potential emissions during a delayed repair, the date 
the delay of repair began is equivalent to the day the repair would 
have had to be completed if the repair had not been delayed.
    Comment: One commenter stated that the proposed requirements to 
identify the ``measured or estimated average annual regulated material 
concentration of process fluid or intervening cooling fluid processed 
in each heat exchanger'' will be a very burdensome and unnecessary 
ongoing requirement rather than one-time requirement as specified in 40 
CFR 63.655(i)(4)(i).
    Response: We agree that we should retain this as a one-time 
requirement. We did not intend to make this an ongoing requirement. The 
revised language cited by the commenter was part of the proposed 
Uniform Standards, which we proposed to cross-reference from Refinery 
MACT 1 but are not finalizing in this action. We are not revising the 
``one-time'' requirement as specified in 40 CFR 63.655(i)(4)(i).
    Comment: One commenter suggested deleting paragraphs (b) and (c) in 
40 CFR 65.620 (i.e., reporting the number of heat exchange systems in 
regulated material service found to be leaking and the summary of the 
monitoring data that indicate a leak) because they duplicate the 
information required by paragraph (d) (i.e., reporting the date a leak 
was identified, the date the source of the leak was identified and the 
date of repair) or are unnecessary. Alternatively, the commenter 
suggested that the EPA should at least revise 40 CFR 65.620(b) to 
require reporting of the number of leaking heat exchangers rather than 
heat exchange systems, and revise 40 CFR 65.620(c) to clarify what 
monitoring data to report and eliminate the redundancy.
    Response: The comments refer to the reporting and recordkeeping 
provisions that we proposed to codify as part of the Uniform Standards, 
which we are not finalizing in this action. The similar provisions in 
Refinery MACT 1, which we are retaining rather than cross-referencing 
the Uniform Standards, as proposed, are the reporting provisions in 40 
CFR 63.655(g)(9)(ii) through (iv). We disagree with the commenter that 
there is undue overlap in these provisions. The number of heat exchange 
systems at the plant site found to be leaking (40 CFR 63.655(g)(9)(ii)) 
provides a useful summary to the report review. Analogous to the number 
of fugitive components found to be leaking over a semiannual period, 
which is also required to be reported under Refinery MACT 1, this 
information is an indicator of both leak program effectiveness and the 
refinery's operating and maintenance practices. While one could count 
each entry in the list of leaking heat exchange systems required in 40 
CFR 63.655(g)(9)(iii), we do not consider this duplicative of the list. 
We do agree that the ``summary of monitoring data'' could be more 
clearly delineated. To address this concern, we have revised the 
provisions in 40 CFR 63.655(g)(9)(iii) to specifically list the desired 
reporting elements. We also consolidated some of the reporting elements 
from 40 CFR 63.655(g)(9)(iv) into 40 CFR 63.655(g)(9)(iii) and revised 
40 CFR 63.655(g)(9)(iv) to focus on reporting elements for leaks that 
were repaired during the reporting period. These reporting requirements 
are now more clear and distinct with no duplication.
    Comment: One commenter noted that it would be burdensome to 
identify, characterize or include pump seal coolers and sample coolers 
in the heat exchanger inventory and applicability determination. The 
commenter stated

[[Page 37144]]

that there is no need for this requirement because those that are once-
through coolers should be presumed to meet the low flow exemption 
criteria and those that are part of a recirculating system with large 
heat exchangers would be effectively regulated by monitoring of the 
cooling tower return lines.
    Response: We never intended to require monitoring of sample coolers 
and pump seal coolers. As discussed previously, sample coolers and pump 
seal coolers are specifically excluded from the definition of heat 
exchange system in today's final rule, so these coolers do not have to 
be identified as part of the heat exchange system recordkeeping 
provisions.

V. Summary of Impacts

    These final amendments will have no cost, environmental, energy or 
economic impacts beyond those impacts presented in the October 2009 
final rule for heat exchange systems at petroleum refineries. If the 
owner or operator of an existing petroleum refinery elects the 
quarterly monitoring alternative at the lower leak definition or if the 
owner or operator of a once-through system can aggregate flows across 
process unit boundaries, we anticipate that the facility will realize a 
net cost savings compared to the costs estimated for the October 2009 
final rule. All other amendments are projected to be cost-neutral.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this 
action is a ``significant regulatory action'' because it may raise 
novel legal or policy issues. Accordingly, the EPA submitted this 
action to the Office of Management and Budget (OMB) for review under 
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and 
any changes made in response to OMB recommendations have been 
documented in the docket for this action.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
The final amendments are clarifications and technical corrections that 
do not affect the estimated burden of the existing rule. Therefore, we 
have not revised the information collection request for the existing 
rule. However, OMB has previously approved the information collection 
requirements contained in the existing rule (40 CFR Part 63, subpart 
CC) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 
3501, et seq., and has assigned OMB control number 2060-0340. The OMB 
control numbers for the EPA's regulations are listed in 40 CFR Part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to 
prepare a regulatory flexibility analysis of any rule subject to notice 
and comment rulemaking requirements under the Administrative Procedure 
Act or any other statute unless the agency certifies that the rule will 
not have a significant economic impact on a substantial number of small 
entities (SISNOSE). Small entities include small businesses, small 
organizations and small governmental jurisdictions.
    For the purposes of assessing the impacts of this final rule on 
small entities, small entity is defined as: (1) A small business that 
meets the Small Business Administration size standards for small 
businesses at 13 CFR 121.201 (a firm having no more than 1,500 
employees); (2) a small governmental jurisdiction that is a government 
of a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of this final rule on small 
entities, I certify that this action will not have a SISNOSE. In 
determining whether a rule has a SISNOSE, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the rule on small entities.'' 5 U.S.C. 603 and 604. 
Thus, an agency may certify that a rule will not have a SISNOSE if the 
rule relieves regulatory burden, or otherwise has a positive economic 
effect on all of the small entities subject to the rule.
    Based on our economic impact analysis, the amendments will have no 
direct cost impacts (or they will result in a nationwide net cost 
savings). No small entities are expected to incur annualized costs as a 
result of the final amendments; therefore, no adverse economic impacts 
are expected for any small or large entity. Thus, the costs associated 
with the final amendments will not result in any ``significant'' 
adverse economic impact for any small entity. We have, therefore, 
concluded that today's final rule will relieve regulatory burden for 
all affected small entities.

D. Unfunded Mandates Reform Act

    This rule does not contain a federal mandate that may result in 
expenditures of $100 million or more for state, local and tribal 
governments, in the aggregate, or to the private sector in any one 
year. As discussed earlier in this preamble, these amendments are cost 
neutral and may result in net cost savings for the private sector. 
Thus, this rule is not subject to the requirements of sections 202 or 
205 of the Unfunded Mandates Reform Act (UMRA).
    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. The final 
amendments contain no requirements that apply to such governments, and 
impose no obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. These final amendments do not add 
new control and performance demonstration requirements. They do not 
modify existing responsibilities or create new responsibilities among 
EPA Regional offices, states or local enforcement agencies. Thus, 
Executive Order 13132 does not apply to this action. In the spirit of 
Executive Order 13132, and consistent with EPA policy to promote 
communications between the EPA and state and local governments, the EPA 
specifically solicited comment on the proposed amendments from state 
and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). The final 
amendments will not have substantial direct effects on tribal 
governments, on the relationship between the federal government and 
Indian tribes, or on the distribution of power and responsibilities 
between the federal government and Indian tribes, as specified in 
Executive Order 13175. The

[[Page 37145]]

final amendments impose no requirements on tribal governments. Thus, 
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 
1997) as applying to those regulatory actions that concern health or 
safety risks, such that the analysis required under section 5-501 of 
the Order has the potential to influence the regulation. This action is 
not subject to Executive Order 13045 because it is based solely on 
technology performance.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' as defined in 
Executive Order 13211 (66 FR 28355, May 22, 2001) because it is not 
likely to have a significant adverse effect on the supply, distribution 
or use of energy. Further, we have concluded that the final amendments 
are not likely to have any adverse energy effects because they are cost 
neutral and may result in cost savings if the quarterly monitoring 
option is elected.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs the EPA to use voluntary consensus standards (VCS) in its 
regulatory activities, unless to do so would be inconsistent with 
applicable law or otherwise impractical. Voluntary consensus standards 
are technical standards (e.g., materials specifications, test methods, 
sampling procedures, and business practices) that are developed or 
adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, 
through OMB, explanations when the agency decides not to use available 
and applicable VCS.
    This action does not involve any new technical standards. 
Therefore, the EPA did not consider the use of any additional VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
federal executive policy on environmental justice (EJ). Its main 
provision directs federal agencies, to the greatest extent practicable 
and permitted by law, to make EJ part of their mission by identifying 
and addressing, as appropriate, disproportionately high and adverse 
human health or environmental effects of their programs, policies and 
activities on minority populations and low-income populations in the 
United States.
    The EPA has determined that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. The final amendments do not relax the control measures on 
regulated sources, and, therefore, do not change the level of 
environmental protection.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801, et seq., as added by 
the Small Business Regulatory Enforcement Fairness Act of 1996, 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. The EPA will submit a report containing 
this final rule and other required information to the United States 
Senate, the United States House of Representatives and the Comptroller 
General of the United States prior to publication of the final rule in 
the Federal Register. A major rule cannot take effect until 60 days 
after it is published in the Federal Register. This action is not a 
``major rule'' as defined by 5 U.S.C. 804(2). This final rule will be 
effective on June 20, 2013.

List of Subjects in 40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous 
substances, Incorporation by reference, Reporting and recordkeeping 
requirements.

    Dated: June 12, 2013.
Bob Perciasepe,
Acting Administrator.

    For the reasons stated in the preamble, the Environmental 
Protection Agency amends title 40, chapter I, of the Code of Federal 
Regulations as follows:

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

0
1. The authority citation for part 63 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart A--General Provisions

0
2. Section 63.14 is amended by revising paragraph (n)(1) to read as 
follows:


Sec.  63.14  Incorporations by reference.

* * * * *
    (n) * * *
    (1) ``Air Stripping Method (Modified El Paso Method) for 
Determination of Volatile Organic Compound Emissions from Water 
Sources'' (Modified El Paso Method), Revision Number One, dated January 
2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, 
January 31, 2003, IBR approved for Sec. Sec.  63.654(c), 63.654(g), 
63.655(i), and 63.11920.
* * * * *

Subpart CC--National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries

0
3. Section 63.640 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (c)(8);
0
c. Revising paragraph (h)(1) introductory text, adding paragraph 
(h)(1)(i) and revising paragraph (h)(1)(ii); and
0
d. Removing reserved paragraph (h)(1)(iii) and paragraph (h)(1)(iv).
    The additions and revisions read as follows:


Sec.  63.640  Applicability and designation of affected source.

    (a) This subpart applies to petroleum refining process units and to 
related emissions points that are specified in paragraphs (c)(1) 
through (8) of this section that are located at a plant site and that 
meet the criteria in paragraphs (a)(1) and (2) of this section:
* * * * *
    (c) * * *
    (8) All heat exchange systems, as defined in this subpart.
* * * * *
    (h) * * *
    (1) Except as provided in paragraphs (h)(1)(i) and (ii) of this 
section, new sources that commence construction or reconstruction after 
July 14, 1994, shall be in compliance with this subpart upon initial 
startup or August 18, 1995, whichever is later.
    (i) At new sources that commence construction or reconstruction 
after July 14, 1994, but on or before September 4, 2007, heat exchange 
systems shall be in compliance with the existing source requirements 
for heat exchange systems specified in Sec.  63.654 no later than 
October 29, 2012.

[[Page 37146]]

    (ii) At new sources that commence construction or reconstruction 
after September 4, 2007, heat exchange systems shall be in compliance 
with the new source requirements in Sec.  63.654 upon initial startup 
or October 28, 2009, whichever is later.
* * * * *


0
4. Section 63.641 is amended by revising the definitions of ``Heat 
exchange system'' and ``In organic hazardous air pollutant service'' to 
read as follows:


Sec.  63.641  Definitions.

* * * * *
    Heat exchange system means a device or collection of devices used 
to transfer heat from process fluids to water without intentional 
direct contact of the process fluid with the water (i.e., non-contact 
heat exchanger) and to transport and/or cool the water in a closed-loop 
recirculation system (cooling tower system) or a once-through system 
(e.g., river or pond water). For closed-loop recirculation systems, the 
heat exchange system consists of a cooling tower, all petroleum 
refinery process unit heat exchangers that are in organic HAP service, 
as defined in this subpart, serviced by that cooling tower, and all 
water lines to and from these petroleum refinery process unit heat 
exchangers. For once-through systems, the heat exchange system consists 
of all heat exchangers that are in organic HAP service, as defined in 
this subpart, servicing an individual petroleum refinery process unit 
and all water lines to and from these heat exchangers. Sample coolers 
or pump seal coolers are not considered heat exchangers for the purpose 
of this definition and are not part of the heat exchange system. 
Intentional direct contact with process fluids results in the formation 
of a wastewater.
* * * * *
    In organic hazardous air pollutant service or in organic HAP 
service means that a piece of equipment either contains or contacts a 
fluid (liquid or gas) that is at least 5 percent by weight of total 
organic HAP as determined according to the provisions of Sec.  
63.180(d) of this part and table 1 of this subpart. The provisions of 
Sec.  63.180(d) also specify how to determine that a piece of equipment 
is not in organic HAP service.
* * * * *


0
5. Section 63.654 is amended by:
0
a. Revising paragraphs (b) and (c);
0
b. Revising paragraph (d) introductory text;
0
c. Revising paragraphs (e) and (f);
0
d. Revising paragraph (g) introductory text and paragraph (g)(4).
    The revisions read as follows:


Sec.  63.654  Heat exchange systems.

* * * * *
    (b) A heat exchange system is exempt from the requirements in 
paragraphs (c) through (g) of this section if all heat exchangers 
within the heat exchange system either:
    (1) Operate with the minimum pressure on the cooling water side at 
least 35 kilopascals greater than the maximum pressure on the process 
side; or
    (2) Employ an intervening cooling fluid containing less than 5 
percent by weight of total organic HAP, as determined according to the 
provisions of Sec.  63.180(d) of this part and table 1 of this subpart, 
between the process and the cooling water. This intervening fluid must 
serve to isolate the cooling water from the process fluid and must not 
be sent through a cooling tower or discharged. For purposes of this 
section, discharge does not include emptying for maintenance purposes.
    (c) The owner or operator must perform monitoring to identify leaks 
of total strippable volatile organic compounds (VOC) from each heat 
exchange system subject to the requirements of this subpart according 
to the procedures in paragraphs (c)(1) through (6) of this section.
    (1) Monitoring locations for closed-loop recirculation heat 
exchange systems. For each closed loop recirculating heat exchange 
system, collect and analyze a sample from the location(s) described in 
either paragraph (c)(1)(i) or (c)(1)(ii) of this section.
    (i) Each cooling tower return line or any representative riser 
within the cooling tower prior to exposure to air for each heat 
exchange system.
    (ii) Selected heat exchanger exit line(s) so that each heat 
exchanger or group of heat exchangers within a heat exchange system is 
covered by the selected monitoring location(s).
    (2) Monitoring locations for once-through heat exchange systems. 
For each once-through heat exchange system, collect and analyze a 
sample from the location(s) described in paragraph (c)(2)(i) of this 
section. The owner or operator may also elect to collect and analyze an 
additional sample from the location(s) described in paragraph 
(c)(2)(ii) of this section.
    (i) Selected heat exchanger exit line(s) so that each heat 
exchanger or group of heat exchangers within a heat exchange system is 
covered by the selected monitoring location(s). The selected monitoring 
location may be at a point where discharges from multiple heat exchange 
systems are combined provided that the combined cooling water flow rate 
at the monitoring location does not exceed 40,000 gallons per minute.
    (ii) The inlet water feed line for a once-through heat exchange 
system prior to any heat exchanger. If multiple heat exchange systems 
use the same water feed (i.e., inlet water from the same primary water 
source), the owner or operator may monitor at one representative 
location and use the monitoring results for that sampling location for 
all heat exchange systems that use that same water feed.
    (3) Monitoring method. Determine the total strippable hydrocarbon 
concentration (in parts per million by volume (ppmv) as methane) at 
each monitoring location using the ``Air Stripping Method (Modified El 
Paso Method) for Determination of Volatile Organic Compound Emissions 
from Water Sources'' Revision Number One, dated January 2003, Sampling 
Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by 
Texas Commission on Environmental Quality, January 31, 2003 
(incorporated by reference--see Sec.  63.14) using a flame ionization 
detector (FID) analyzer for on-site determination as described in 
Section 6.1 of the Modified El Paso Method.
    (4) Monitoring frequency and leak action level for existing 
sources. For a heat exchange system at an existing source, the owner or 
operator must comply with the monitoring frequency and leak action 
level as defined in paragraph (c)(4)(i) of this section or comply with 
the monitoring frequency and leak action level as defined in paragraph 
(c)(4)(ii) of this section. The owner or operator of an affected heat 
exchange system may choose to comply with paragraph (c)(4)(i) of this 
section for some heat exchange systems at the petroleum refinery and 
comply with paragraph (c)(4)(ii) of this section for other heat 
exchange systems. However, for each affected heat exchange system, the 
owner or operator of an affected heat exchange system must elect one 
monitoring alternative that will apply at all times. If the owner or 
operator intends to change the monitoring alternative that applies to a 
heat exchange system, the owner or operator must notify the 
Administrator 30 days in advance of such a change. All ``leaks'' 
identified prior to changing monitoring alternatives must be repaired. 
The monitoring frequencies specified in paragraphs (c)(4)(i) and (ii) 
of this section also apply to the inlet water feed line for a once-
through heat exchange

[[Page 37147]]

system, if monitoring of the inlet water feed is elected as provided in 
paragraph (c)(2)(ii) of this section.
    (i) Monitor monthly using a leak action level defined as a total 
strippable hydrocarbon concentration (as methane) in the stripping gas 
of 6.2 ppmv.
    (ii) Monitor quarterly using a leak action level defined as a total 
strippable hydrocarbon concentration (as methane) in the stripping gas 
of 3.1 ppmv unless repair is delayed as provided in paragraph (f) of 
this section. If a repair is delayed as provided in paragraph (f) of 
this section, monitor monthly.
    (5) Monitoring frequency and leak action level for new sources. For 
a heat exchange system at a new source, the owner or operator must 
monitor monthly using a leak action level defined as a total strippable 
hydrocarbon concentration (as methane) in the stripping gas of 3.1 
ppmv.
    (6) Leak definition. A leak is defined as described in paragraph 
(c)(6)(i) or (c)(6)(ii) of this section, as applicable.
    (i) For once-through heat exchange systems for which the inlet 
water feed is monitored as described in paragraph (c)(2)(ii) of this 
section, a leak is detected if the difference in the measurement value 
of the sample taken from a location specified in paragraph (c)(2)(i) of 
this section and the measurement value of the corresponding sample 
taken from the location specified in paragraph (c)(2)(ii) of this 
section equals or exceeds the leak action level.
    (ii) For all other heat exchange systems, a leak is detected if a 
measurement value of the sample taken from a location specified in 
either paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) of this section 
equals or exceeds the leak action level.
    (d) If a leak is detected, the owner or operator must repair the 
leak to reduce the measured concentration to below the applicable 
action level as soon as practicable, but no later than 45 days after 
identifying the leak, except as specified in paragraphs (e) and (f) of 
this section. Repair includes re-monitoring at the monitoring location 
where the leak was identified according to the method specified in 
paragraph (c)(3) of this section to verify that the measured 
concentration is below the applicable action level. Actions that can be 
taken to achieve repair include but are not limited to:
* * * * *
    (e) If the owner or operator detects a leak when monitoring a 
cooling tower return line under paragraph (c)(1)(i) of this section, 
the owner or operator may conduct additional monitoring of each heat 
exchanger or group of heat exchangers associated with the heat exchange 
system for which the leak was detected as provided under paragraph 
(c)(1)(ii) of this section. If no leaks are detected when monitoring 
according to the requirements of paragraph (c)(1)(ii) of this section, 
the heat exchange system is considered to meet the repair requirements 
through re-monitoring of the heat exchange system as provided in 
paragraph (d) of this section.
    (f) The owner or operator may delay the repair of a leaking heat 
exchanger when one of the conditions in paragraph (f)(1) or (f)(2) of 
this section is met and the leak is less than the delay of repair 
action level specified in paragraph (f)(3) of this section. The owner 
or operator must determine if a delay of repair is necessary as soon as 
practicable, but no later than 45 days after first identifying the 
leak.
    (1) If the repair is technically infeasible without a shutdown and 
the total strippable hydrocarbon concentration is initially and remains 
less than the delay of repair action level for all monthly monitoring 
periods during the delay of repair, the owner or operator may delay 
repair until the next scheduled shutdown of the heat exchange system. 
If, during subsequent monthly monitoring, the delay of repair action 
level is exceeded, the owner or operator must repair the leak within 30 
days of the monitoring event in which the leak was equal to or exceeded 
the delay of repair action level.
    (2) If the necessary equipment, parts, or personnel are not 
available and the total strippable hydrocarbon concentration is 
initially and remains less than the delay of repair action level for 
all monthly monitoring periods during the delay of repair, the owner or 
operator may delay the repair for a maximum of 120 calendar days. The 
owner or operator must demonstrate that the necessary equipment, parts, 
or personnel were not available. If, during subsequent monthly 
monitoring, the delay of repair action level is exceeded, the owner or 
operator must repair the leak within 30 days of the monitoring event in 
which the leak was equal to or exceeded the delay of repair action 
level.
    (3) The delay of repair action level is a total strippable 
hydrocarbon concentration (as methane) in the stripping gas of 62 ppmv. 
The delay of repair action level is assessed as described in paragraph 
(f)(3)(i) or (f)(3)(ii) of this section, as applicable.
    (i) For once-through heat exchange systems for which the inlet 
water feed is monitored as described in paragraph (c)(2)(ii) of this 
section, the delay of repair action level is exceeded if the difference 
in the measurement value of the sample taken from a location specified 
in paragraph (c)(2)(i) of this section and the measurement value of the 
corresponding sample taken from the location specified in paragraph 
(c)(2)(ii) of this section equals or exceeds the delay of repair action 
level.
    (ii) For all other heat exchange systems, the delay of repair 
action level is exceeded if a measurement value of the sample taken 
from a location specified in either paragraphs (c)(1)(i), (c)(1)(ii), 
or (c)(2)(i) of this section equals or exceeds the delay of repair 
action level.
    (g) To delay the repair under paragraph (f) of this section, the 
owner or operator must record the information in paragraphs (g)(1) 
through (4) of this section.
    (4) An estimate of the potential strippable hydrocarbon emissions 
from the leaking heat exchange system or heat exchanger for each 
required delay of repair monitoring interval following the procedures 
in paragraphs (g)(4)(i) through (iv) of this section.
    (i) Determine the leak concentration as specified in paragraph (c) 
of this section and convert the stripping gas leak concentration (in 
ppmv as methane) to an equivalent liquid concentration, in parts per 
million by weight (ppmw), using equation 7-1 from ``Air Stripping 
Method (Modified El Paso Method) for Determination of Volatile Organic 
Compound Emissions from Water Sources'' Revision Number One, dated 
January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower 
Monitoring, prepared by Texas Commission on Environmental Quality, 
January 31, 2003 (incorporated by reference--see Sec.  63.14) and the 
molecular weight of 16 grams per mole (g/mol) for methane.
    (ii) Determine the mass flow rate of the cooling water at the 
monitoring location where the leak was detected. If the monitoring 
location is an individual cooling tower riser, determine the total 
cooling water mass flow rate to the cooling tower. Cooling water mass 
flow rates may be determined using direct measurement, pump curves, 
heat balance calculations, or other engineering methods. Volumetric 
flow measurements may be used and converted to mass flow rates using 
the density of water at the specific monitoring location temperature or 
using the default density of water at 25 degrees Celsius, which is 997 
kilograms per cubic meter or 8.32 pounds per gallon.
    (iii) For delay of repair monitoring intervals prior to repair of 
the leak,

[[Page 37148]]

calculate the potential strippable hydrocarbon emissions for the 
leaking heat exchange system or heat exchanger for the monitoring 
interval by multiplying the leak concentration in the cooling water, 
ppmw, determined in (g)(4)(i) of this section, by the mass flow rate of 
the cooling water determined in (g)(4)(ii) of this section and by the 
duration of the delay of repair monitoring interval. The duration of 
the delay of repair monitoring interval is the time period starting at 
midnight on the day of the previous monitoring event or at midnight on 
the day the repair would have had to be completed if the repair had not 
been delayed, whichever is later, and ending at midnight of the day the 
of the current monitoring event.
    (iv) For delay of repair monitoring intervals ending with a 
repaired leak, calculate the potential strippable hydrocarbon emissions 
for the leaking heat exchange system or heat exchanger for the final 
delay of repair monitoring interval by multiplying the duration of the 
final delay of repair monitoring interval by the leak concentration and 
cooling water flow rates determined for the last monitoring event prior 
to the re-monitoring event used to verify the leak was repaired. The 
duration of the final delay of repair monitoring interval is the time 
period starting at midnight of the day of the last monitoring event 
prior to re-monitoring to verify the leak was repaired and ending at 
the time of the re-monitoring event that verified that the leak was 
repaired.

0
6. Section 63.655 is amended by:
0
a. Revising paragraph (f)(1)(vi);
0
b. Revising paragraph (g)(9);
0
c. Adding paragraph (h)(7); and
0
d. Revising paragraph (i)(4).
    The addition and revisions read as follows:


Sec.  63.655  Reporting and recordkeeping requirements.

* * * * *
    (f) * * *
    (1) * * *
    (vi) For each heat exchange system, identification of the heat 
exchange systems that are subject to the requirements of this subpart. 
For heat exchange systems at existing sources, the owner or operator 
shall indicate whether monitoring will be conducted as specified in 
Sec.  63.654(c)(4)(i) or Sec.  63.654(c)(4)(ii).
* * * * *
    (g) * * *
    (9) For heat exchange systems, Periodic Reports must include the 
following information:
    (i) The number of heat exchange systems at the plant site subject 
to the monitoring requirements in Sec.  63.654.
    (ii) The number of heat exchange systems at the plant site found to 
be leaking.
    (iii) For each monitoring location where the total strippable 
hydrocarbon concentration was determined to be equal to or greater than 
the applicable leak definitions specified in Sec.  63.654(c)(6), 
identification of the monitoring location (e.g., unique monitoring 
location or heat exchange system ID number), the measured total 
strippable hydrocarbon concentration, the date the leak was first 
identified, and, if applicable, the date the source of the leak was 
identified;
    (iv) For leaks that were repaired during the reporting period 
(including delayed repairs), identification of the monitoring location 
associated with the repaired leak, the total strippable hydrocarbon 
concentration measured during re-monitoring to verify repair, and the 
re-monitoring date (i.e., the effective date of repair); and
    (v) For each delayed repair, identification of the monitoring 
location associated with the leak for which repair is delayed, the date 
when the delay of repair began, the date the repair is expected to be 
completed (if the leak is not repaired during the reporting period), 
the total strippable hydrocarbon concentration and date of each 
monitoring event conducted on the delayed repair during the reporting 
period, and an estimate of the potential strippable hydrocarbon 
emissions over the reporting period associated with the delayed repair.
    (h) * * *
    (7) The owner or operator of a heat exchange system at an existing 
source must notify the Administrator at least 30 calendar days prior to 
changing from one of the monitoring options specified in Sec.  
63.654(c)(4) to the other.
    (i) * * *
    (4) The owner or operator of a heat exchange system subject to this 
subpart shall comply with the recordkeeping requirements in paragraphs 
(i)(4)(i) through (v) of this section and retain these records for 5 
years.
    (i) Identification of all petroleum refinery process unit heat 
exchangers at the facility and the average annual HAP concentration of 
process fluid or intervening cooling fluid estimated when developing 
the Notification of Compliance Status report.
    (ii) Identification of all heat exchange systems subject to the 
monitoring requirements in Sec.  63.654 and identification of all heat 
exchange systems that are exempt from the monitoring requirements 
according to the provisions in Sec.  63.654(b). For each heat exchange 
system that is subject to the monitoring requirements in Sec.  63.654, 
this must include identification of all heat exchangers within each 
heat exchange system, and, for closed-loop recirculation systems, the 
cooling tower included in each heat exchange system.
    (iii) Results of the following monitoring data for each required 
monitoring event:
    (A) Date/time of event.
    (B) Barometric pressure.
    (C) El Paso air stripping apparatus water flow milliliter/minute 
(ml/min) and air flow, ml/min, and air temperature, [deg]Celsius.
    (D) FID reading (ppmv).
    (E) Length of sampling period.
    (F) Sample volume.
    (G) Calibration information identified in Section 5.4.2 of the 
``Air Stripping Method (Modified El Paso Method) for Determination of 
Volatile Organic Compound Emissions from Water Sources'' Revision 
Number One, dated January 2003, Sampling Procedures Manual, Appendix P: 
Cooling Tower Monitoring, prepared by Texas Commission on Environmental 
Quality, January 31, 2003 (incorporated by reference--see Sec.  63.14).
    (iv) The date when a leak was identified, the date the source of 
the leak was identified, and the date when the heat exchanger was 
repaired or taken out of service.
    (v) If a repair is delayed, the reason for the delay, the schedule 
for completing the repair, the heat exchange exit line flow or cooling 
tower return line average flow rate at the monitoring location (in 
gallons/minute), and the estimate of potential strippable hydrocarbon 
emissions for each required monitoring interval during the delay of 
repair.
* * * * *
[FR Doc. 2013-14624 Filed 6-19-13; 8:45 am]
BILLING CODE 6560-50-P