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EO 12866_Refinery MACT 2060-0146 FinalAmendments_20130423 

6560-50-P 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 63 

[EPA-HQ-OAR-2003-0146; FRL- ] 

RIN 2060-AP84 

National Emission Standards for Hazardous Air Pollutants From 

Petroleum Refineries 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This action amends the national emission standards for 

hazardous air pollutants for heat exchange systems at petroleum 

refineries located at 40 CFR part 63, subpart CC. 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. 
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DATES: The final amendments are effective on [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER]. The incorporation by 

reference of certain publications listed in the final rule 

amendments is approved by the Director of the Federal Register 

as of [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

ADDRESSES: The EPA has established a docket for this action 

under Docket ID No. EPA-HQ-OAR-2003-0146. All documents in the 

docket are listed in the www.regulations.gov index. Although 

listed in the index, some information is not publicly available, 

e.g., confidential business information (CBI) or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either 

electronically in www.regulations.gov or in hard copy at the EPA 

Docket Center, National Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries, EPA West Building, Room 

3334, 1301 Constitution Ave., NW, Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The telephone number for the 

Public Reading Room is (202) 566-1744, and the telephone number 

for the Air Docket is (202) 566-1742. 
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FOR FURTHER INFORMATION CONTACT: Ms. Brenda Shine, Office of Air 

Quality Planning and Standards, Sector Policies and Programs 

Division, Refining and Chemicals Group (E143-01), Environmental 

Protection Agency, Research Triangle Park, NC 27711, telephone 

number: (919) 541-3608; fax number: (919) 541-0246; email 

address: shine.brenda@epa.gov. 

SUPPLEMENTARY INFORMATION: The information in this preamble is 

organized as follows: 

I. General Information 

A. Does this action apply to me? 

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

C. Judicial Review 

II. Background Information 

A. Executive Summary 

B. Background of the Refinery NESHAP 

III. Summary of the Final Amendments to NESHAP for Petroleum 

Refineries and Changes Since Proposal 

IV. Summary of Comments and Responses 

A. Uniform Standards for Heat Exchange Systems 

B. Refinery MACT 1 Requirements for Heat Exchange Systems 

V. Summary of Impacts 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act 

J. Executive Order 12898: Federal Actions to Address 
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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: 

Category NAICS1 Code Examples of Regulated 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 
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(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 [INSERT DATE 60 DAYS FROM 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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. 
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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
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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 
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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 crossreferencing 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 §63.14) within the 
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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 
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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 bestcontrolled 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 bestperforming 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. 
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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 
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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 crossreference 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 
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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 
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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 
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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 §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. 
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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 
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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 
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calculate the emissions projected over each monitoring interval 

and sum these estimates for the period covered by the semiannual 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. 
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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
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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
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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 nonrefinery 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, 
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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 
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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 
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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 
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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 
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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 
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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. EPAHQ-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 bestperforming heat exchange systems were identical, we determined 
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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 
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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 
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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 oncethrough 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 
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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 
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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-
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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 
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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 
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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 
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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 oncethrough 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 
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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 
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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 
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exchangers within a single heat exchange system must use the 

same monitoring frequency and leak definition. 

Comment: Two commenters noted that section 5.1.1.4 of the 

Modified El Paso Method specifies that samples must be drawn 

from a location prior to the risers. The commenter requested 

clarification that monitoring may instead be conducted either 

prior to the risers or in any individual riser because the 

concentration of hydrocarbons is distributed equally to each 

riser and the system has no openings to the atmosphere prior to 

discharge into the cooling tower cells. They also noted that 

refineries often monitor in a riser and changes needed to enable 

monitoring prior to the riser would require a significant 

capital expenditure. 

Response: The final amendments describe monitoring 

locations specific for Refinery MACT 1 and then separately 

describes the allowed monitoring methods. Reference to the 

Modified El Paso Method is confined to the monitoring method 

section of Refinery MACT 1, and the Modified El Paso Method’s 

restriction on sampling in the riser is not applicable. 

Nonetheless, we have provided specific clarifications in the 

monitoring location section that monitoring in the cooling tower 

riser (prior to exposure to the atmosphere) is allowed. 
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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 
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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 (°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 °F, and allowing subtraction of compounds with boiling 

points greater than 140 °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 
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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 °F. Hexane, benzene and 

toluene all have boiling points above 140 °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 °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 °F, it is incorrect to conclude that the 
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Modified El Paso Method will not measure any compounds with 

boiling points greater than 140 °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 °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 
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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 backcalculation 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 
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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 
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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 
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HRVOC Rule (TAC Title 30 Part I Chapter 115 Div. 2 §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-OAR2003-0146-0230), 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 
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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 
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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 
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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 
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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 
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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
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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. 
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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. 
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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. 
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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 
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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 
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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 
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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. 
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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 oncethrough 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 costneutral. 

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 
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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. 
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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-forprofit 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 USC 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 
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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. 

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 
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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. 
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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 No. 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 
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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. 
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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 [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 
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National Emission Standards for Hazardous Air Pollutants From 

Petroleum Refineries 

Page 68 of 87 

List of Subjects in 40 CFR Part 63 

Environmental protection, Air pollution control, Hazardous 

substances, Incorporation by reference, Reporting and 

recordkeeping requirements. 

 

Dated: 

 

Lisa P. Jackson, 

Administrator. 

 
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For the reasons stated in the preamble, title 40, chapter 

I, of the Code of Federal Regulations is amended as follows: 

PART 63--[AMENDED] 

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

follows: 

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

Subpart A--[AMENDED] 

2. Section 63.14 is amended by revising paragraph (n)(1) as 

follows: 

§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 

§§63.654(c), 63.654(g), 63.655(i), and 63.11920. 

* * * * * 

Subpart CC--[AMENDED] 

3. Section 63.640 is amended by: 

a. Revising paragraph (a) introductory text; 

b. Revising paragraph (c)(8); and 

c. Revising paragraph (h)(1). 
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The revisions read as follows: 

§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 §63.654 no later than October 29, 2012. 

(iv) At new sources that commence construction or 

reconstruction after September 4, 2007, heat exchange systems 
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shall be in compliance with the new source requirements in 

§63.654 upon initial startup or October 28, 2009, whichever is 

later. 

* * * * * 

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: 

§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 
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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 §63.180(d) of subpart H of this part and table 1 

of this subpart. The provisions of §63.180(d) also specify how 

to determine that a piece of equipment is not in organic HAP 

service. 

* * * * * 

5. Section 63.654 is amended by: 

a. Revising paragraphs (b) and (c); 

b. Revising paragraph (d) introductory text; 

c. Revising paragraphs (e) and (f); 

d. Revising paragraph (g) introductory text and paragraph 

(g)(4). 

The revisions read as follows: 

§63.654 Heat exchange systems. 

* * * * * 
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(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 §63.180(d) of subpart H 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 
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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 
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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 §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 
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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 
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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 remonitoring at the monitoring location where the leak was 
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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 remonitoring 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. 
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(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 
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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 
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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 §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 
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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 
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delay of repair monitoring interval is the time period starting 

at midnight of the day of the last monitoring event prior to remonitoring to verify the leak was repaired and ending at the 

time of the re-monitoring event that verified that the leak was 

repaired. 

6. Section 63.655 is amended by: 

a. Revising paragraph (f)(1)(vi); 

b. Revising paragraph (g)(9); 

c. Adding paragraph (h)(7); and 

d. Revising paragraph (i)(4). 

The addition and revisions read as follows: 

§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 §63.654(c)(4)(i) or §63.654(c)(4)(ii). 

* * * * * 

(g) * * * 

(9) For heat exchange systems, Periodic Reports must 

include the following information: 
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(i) The number of heat exchange systems at the plant site 

subject to the monitoring requirements in §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 

§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 remonitoring 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 
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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 §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 §63.654 and identification of all 

heat exchange systems that are exempt from the monitoring 

requirements according to the provisions in §63.654(b). For each 

heat exchange system that is subject to the monitoring 

requirements in §63.654, this must include identification of all 
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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, °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 §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. 
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(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. 

* * * * *