[Federal Register Volume 78, Number 119 (Thursday, June 20, 2013)]
[Rules and Regulations]
[Pages 37133-37148]
[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<PHONE_NUMBER>, and the
telephone number for the Air Docket is<PHONE_NUMBER>.

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:<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
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:

------------------------------------------------------------------------
                                                   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 http://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

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

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

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.

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

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

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 <IP_ADDRESS> 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

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''

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

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

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

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.

    (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

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,

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