Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37133 

not alter the relationship or the 

distribution of power and 

responsibilities established in the CAA. 

This rule also is not subject to Executive 

Order 13045 ‘‘Protection of Children 

from Environmental Health Risks and 

Safety Risks’’ (62 FR 19885, April 23, 

1997), because it is not economically 

significant. In addition, this rule does 

not involve technical standards, thus 

the requirements of section 12(d) of the 

National Technology Transfer and 

Advancement Act of 1995 (15 U.S.C. 

272 note) do not apply. This rule also 

does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act of 1995 

(44 U.S.C. 3501 et seq.). 

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. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the 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). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements, Volatile organic 

compounds. 

Dated: June 3, 2013. 

A. Stanley Meiburg, 

Acting Regional Administrator, Region 4. 

40 CFR part 52 is corrected by making 

the following correcting amendments: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart K—Florida 

§ 52.520 [Amended] 

■ 2. Section 52.520(c) is amended under 

Chapter 62–297 by removing the entries 

for ‘‘62–297.411’’, ‘‘62–297.412’’, ‘‘62– 

297.413’’, ‘‘62–297.415’’, ‘‘62–297.416’’, 

‘‘62–297.417’’ and ‘‘62–297.423’’. 

[FR Doc. 2013–14509 Filed 6–19–13; 8:45 am] 

BILLING CODE 6560–50–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2003–0146; FRL–9751–4] 

RIN 2060–AP84 

National Emission Standards for 

Hazardous Air Pollutants From 

Petroleum Refineries 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This action amends the 

national emission standards for 

hazardous air pollutants for heat 

exchange systems at petroleum 

refineries. The amendments address 

issues raised in a petition for 

reconsideration of the EPA’s final rule 

setting maximum achievable control 

technology rules for these systems and 

also provides additional clarity and 

regulatory flexibility with regard to that 

rule. This action does not change the 

level of environmental protection 

provided under those standards. The 

final amendments do not add any new 

cost burdens to the refining industry 

and may result in cost savings by 

establishing an additional monitoring 

option that sources may use in lieu of 

the monitoring provided in the original 

standard. 

DATES: The final amendments are 

effective on June 20, 2013. The 

incorporation by reference of certain 

publications listed in the final rule 

amendments is approved by the Director 

of the Federal Register as of June 20, 

2013. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2003–0146. All 

documents in the docket are listed in 

the www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically in 

www.regulations.gov or in hard copy at 

the EPA Docket Center, National 

Emission Standards for Hazardous Air 

Pollutants From Petroleum Refineries, 

EPA West Building, Room 3334, 1301 

Constitution Ave. NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Brenda Shine, Office of Air Quality 

Planning and Standards, Sector Policies 

and Programs Division, Refining and 

Chemicals Group (E143–01), 

Environmental Protection Agency, 

Research Triangle Park, NC 27711, 

telephone number: (919) 541–3608; fax 

number: (919) 541–0246; email address: 

shine.brenda@epa.gov. 

SUPPLEMENTARY INFORMATION: The 

information in this preamble is 

organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I get a copy of this 

document? 

C. Judicial Review 

II. Background Information 

A. Executive Summary 

B. Background of the Refinery NESHAP 

III. Summary of the Final Amendments to 

NESHAP for Petroleum Refineries and 

Changes Since Proposal 

IV. Summary of Comments and Responses 

A. Uniform Standards for Heat Exchange 

Systems 

B. Refinery MACT 1 Requirements for Heat 

Exchange Systems 

V. Summary of Impacts 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. General Information 

A. Does this action apply to me? 

The regulated category and entities 

potentially affected by this final action 

include: 

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37134 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

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 (WWW) through the Technology 

Transfer Network (TTN). Following 

signature, a copy of this final action will 

be posted on the TTN’s policy and 

guidance page for newly proposed or 

promulgated rules at http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

The EPA has created a redline 

document comparing the existing 

regulatory text of 40 CFR Part 63, 

subpart CC and the final amendments to 

aid the public’s ability to understand 

the changes to the regulatory text. This 

document has been placed in the docket 

for this rulemaking (Docket ID No. EPA– 

HQ–OAR–2003–0146). 

C. Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act (CAA), judicial review of this 

final rule is available only by filing a 

petition for review in the United States 

Court of Appeals for the District of 

Columbia Circuit by August 19, 2013. 

Under section 307(d)(7)(B) of the CAA, 

the requirements established by these 

final rules may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. 

Section 307(d)(7)(B) of the CAA 

further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism for 

us to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to the EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

II. Background Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

This action finalizes amendments that 

were proposed on January 6, 2012, to 

address reconsideration issues related to 

the maximum achievable control 

technology standards (MACT) for heat 

exchange systems we promulgated on 

October 28, 2009. This action also 

finalizes additional amendments 

intended to clarify rule provisions and 

to provide additional flexibility. 

2. Summary of Major Provisions 

We are finalizing three significant 

revisions to the standards for heat 

exchange systems that were 

promulgated on October 28, 2009. First, 

we are revising the regulations to 

include an alternative monitoring 

option for heat exchange systems that 

would allow owners and operators at 

existing sources to monitor quarterly 

using a leak action level defined as a 

total strippable hydrocarbon 

concentration (as methane) in the 

stripping gas of 3.1 parts per million by 

volume (ppmv); the current regulations 

(40 CFR 63.654) provide only one 

monitoring option, which requires 

monitoring monthly at a leak action 

level defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 6.2 ppmv. We 

performed modeling of the monitoring 

alternative and the modeling indicates 

that quarterly monitoring at the lower 

leak action level provides equivalent 

emission reductions to monthly 

monitoring at the higher leak action 

level in the existing regulations. These 

amendments also include specific 

recordkeeping and reporting 

requirements for owners and operators 

electing to use the alternative 

monitoring frequency. 

The second significant amendment is 

the revision to the definition of heat 

exchange system to improve clarity 

regarding applicability of the 

monitoring and repair provisions for 

individual heat exchangers within the 

heat exchange system. 

The third significant revision is an 

amendment to the monitoring 

requirements for once-through cooling 

systems to allow monitoring at an 

aggregated location for once-through 

cooling water heat exchange systems, 

provided that the combined cooling 

water flow rate at the monitoring 

location does not exceed 40,000 gallons 

per minute. 

These final amendments do not 

include the proposed cross-referencing 

of the Uniform Standards for Heat 

Exchange Systems (40 CFR Part 65, 

subpart L). These final amendments also 

do not include the use of direct water 

sampling methods that were proposed 

as alternatives to using the ‘‘Air 

Stripping Method (Modified El Paso 

Method) for Determination of Volatile 

Organic Compound Emissions from 

Water Sources’’ (Modified El Paso 

Method), Revision Number One, dated 

January 2003, Sampling Procedures 

Manual, Appendix P: Cooling Tower 

Monitoring, January 31, 2003 

(incorporated by reference—see § 63.14) 

within the Uniform Standards for Heat 

Exchange Systems. The EPA concluded 

that the alternative as proposed was not 

feasible for petroleum refineries and 

that alternatives suggested during the 

comment period were not equivalent. 

3. Costs and Benefits 

The actions we are taking will have 

no cost, environmental, energy or 

economic impacts beyond those impacts 

presented in the October 2009 final rule 

for heat exchange systems at petroleum 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37135 

refineries and may result in a cost 

savings for refiners who select the 

proposed alternative monitoring 

frequency. For sources that choose the 

quarterly monitoring alternative, the 

cost is projected to be less than the cost 

of the monthly monitoring requirement 

in the October 2009 final rule, while 

achieving the same environmental 

impacts. Similarly, sources that choose 

to monitor at an aggregated location, for 

the small number of refineries that 

operate once-through systems, will have 

reduced monitoring costs. The 

clarifications and other changes we are 

proposing in response to 

reconsideration are cost-neutral. 

B. Background of the Refinery NESHAP 

Section 112 of the CAA establishes a 

regulatory process to address emissions 

of hazardous air pollutants (HAP) from 

stationary sources. After the EPA has 

identified categories of sources emitting 

one or more of the HAP listed in section 

112(b) of the CAA, section 112(d) calls 

for us to promulgate national emission 

standards for hazardous air pollutants 

(NESHAP) for those sources. For ‘‘major 

sources’’ that emit or have the potential 

to emit any single HAP at a rate of 10 

tons or more per year or any 

combination of HAP at a rate of 25 tons 

or more per year, these technologybased 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 bestperforming 12 percent of existing 

sources in the category or subcategory 

(or the best-performing five sources for 

categories or subcategories with fewer 

than 30 sources). In developing MACT, 

we must also consider control options 

that are more stringent than the floor. 

We may establish standards more 

stringent than the floor based on the 

consideration of the cost of achieving 

the emissions reductions, any non-air 

quality health and environmental 

impacts and energy requirements. 

We published the first set of MACT 

standards for petroleum refineries (40 

CFR Part 63, subpart CC) on August 18, 

1995 (60 FR 43620). These standards are 

commonly referred to as the ‘‘Refinery 

MACT 1’’ standards because certain 

process vents were excluded from this 

source category and subsequently 

regulated under a second MACT 

standard specific to these petroleum 

refinery process vents (40 CFR Part 63, 

subpart UUU, referred to as ‘‘Refinery 

MACT 2’’). 

We issued an initial proposed rule to 

include requirements for heat exchange 

systems for the petroleum refineries 

subject to the Refinery MACT 1 on 

September 4, 2007, and held a public 

hearing in Houston, Texas, on 

November 27, 2007. In response to 

public comments on the initial 

proposal, we collected additional 

information and revised our analysis of 

the MACT floor. Based on the results of 

these additional analyses, we issued a 

supplemental proposal on November 10, 

2008, that proposed a new MACT floor 

for heat exchange systems. A public 

hearing for the supplemental proposal 

was held in Research Triangle Park, 

North Carolina, on November 25, 2008. 

We took final action to establish 

standards for heat exchange systems in 

the Refinery MACT 1 standards (40 CFR 

Part 63, subpart CC) on October 28, 

2009. 

On December 23, 2009, the American 

Petroleum Institute (API) requested an 

administrative reconsideration under 

CAA section 307(d)(7)(B) of certain 

provisions of 40 CFR Part 63, subpart 

CC that they had identified in an April 

7, 2009, letter to the EPA. On January 

6, 2012, we issued a proposed rule 

addressing the issues in the 

reconsideration petition and proposed 

amendments to 40 CFR Part 63, subpart 

CC. As part of the January 6, 2012, 

proposal, we also proposed Uniform 

Standards for Heat Exchange Systems 

(40 CFR Part 65, subpart L), which 

included the same substantive 

provisions for heat exchange systems 

that were in the October 2009 Refinery 

MACT 1 final standards (40 CFR Part 

63, subpart CC). We proposed to remove 

from the Refinery MACT 1 standards 

most of the substantive provisions 

addressing heat exchange systems and 

to cross-reference the Uniform 

Standards from Refinery MACT 1. 

III. Summary of Final Amendments to 

NESHAP for Petroleum Refineries and 

Changes Since Proposal 

As described in section II.B. of this 

preamble, we proposed, on January 6, 

2012, Uniform Standards for Heat 

Exchange Systems as 40 CFR Part 65, 

subpart L and amendments to Refinery 

MACT 1 (40 CFR Part 63, subpart CC). 

We are not finalizing the Uniform 

Standards for Heat Exchange Systems at 

this time because we are still evaluating 

comments received on the March 26, 

2012, proposed Uniform Standards for 

storage vessels, equipment leaks and 

closed vent system and control devices 

(see 77 FR 17898). We believe it is 

appropriate to consider all the 

comments received on the Uniform 

Standards proposed rules together, 

particularly since some of the comments 

received on the March 26, 2012, 

proposal relate to the overall concept 

and implementation of Uniform 

Standards across multiple industry 

categories. We are retaining in Refinery 

MACT 1 the substantive requirements 

for heat exchange systems. However, we 

are revising Refinery MACT 1 to 

incorporate many of the substantive 

changes in the work practice standards 

for heat exchange systems at petroleum 

refineries included in the Uniform 

Standards as part of the January 6, 2012, 

proposal. 

First, we are amending the definition 

of ‘‘heat exchange system’’ based on the 

proposed clarification of the definition 

and the public comments received. As 

proposed, we are replacing ‘‘series of 

devices’’ with ‘‘collection of devices.’’ 

In response to comments, we also are 

amending the definition of ‘‘heat 

exchange system’’ to improve clarity 

regarding the applicability of the 

monitoring and repair requirements for 

individual heat exchangers within the 

heat exchange system. Specifically, we 

are revising the definition of ‘‘heat 

exchange system’’ to focus on heat 

exchangers (and not sample coolers) 

that are in organic HAP service and that 

are associated with a petroleum refinery 

process unit. Therefore, we are 

finalizing the definition of ‘‘heat 

exchange system’’ to mean a device or 

collection of devices used to transfer 

heat from process fluids to water 

without intentional direct contact of the 

process fluid with the water (i.e., noncontact 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 

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37136 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

exchangers that are in organic HAP 

service (as defined in this subpart) 

servicing an individual petroleum 

refinery process unit and all water lines 

to and from these heat exchangers. 

Sample coolers or pump seal coolers are 

not considered heat exchangers for the 

purpose of this definition and are not 

part of the heat exchange system. 

Intentional direct contact with process 

fluids results in the formation of a 

wastewater. 

In the January 2012 proposal, we 

included clarifications of the sampling 

requirements and leak action level for 

once-through heat exchange systems 

when determining strippable 

hydrocarbon concentrations for the inlet 

water stream. We are finalizing these 

clarifications as proposed. After 

considering public comments, we are 

also revising the sampling requirement 

for once-through systems to allow 

monitoring at an aggregated location for 

once-through heat exchange systems, 

provided that the combined cooling 

water flow rate at the monitoring 

location does not exceed 40,000 gallons 

per minute. 

In the January 2012 proposal, we also 

proposed a direct water sampling and 

analysis option as an alternative to 

using the ‘‘Air Stripping Method 

(Modified El Paso Method) for 

Determination of Volatile Organic 

Compound Emissions from Water 

Sources’’ (Modified El Paso Method), 

Revision Number One, dated January 

2003, Sampling Procedures Manual, 

Appendix P: Cooling Tower Monitoring, 

January 31, 2003 (incorporated by 

reference—see § 63.14), as well as 

amendments to the recordkeeping and 

reporting requirements when this 

alternative is elected. After considering 

public comments, we are not revising 

Refinery MACT 1 to include this 

alternative. 

In the January 2012 proposal, we 

included an alternative monitoring 

frequency for heat exchange systems at 

existing sources. This monitoring 

frequency is quarterly using a leak 

action level defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 3.1 ppmv; the 

only monitoring frequency in existing 

Refinery MACT 1 is monthly at a leak 

action level defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 6.2 ppmv. We are 

revising Refinery MACT 1 to include the 

alternative monitoring frequency, as 

proposed. 

We proposed a clarification that the 

water flow rate could be determined 

based on direct measurement, pump 

curves, heat balance calculations or 

other engineering methods. We are 

finalizing this clarification as proposed. 

We also proposed clarifications to the 

applicability dates for heat exchange 

systems at new sources. We are 

finalizing these clarifications as 

proposed. 

The proposed Uniform Standards at 

40 CFR 65.610(b) contained three 

exemptions: one based on pressure 

differential, one based on not being ‘‘in 

regulated material service,’’ and one 

based on size (targeted to exclude 

sample coolers). As previously noted, 

we are not finalizing the Uniform 

Standards or the cross-references to 

those Uniform Standards from Refinery 

MACT 1. The corresponding section in 

Refinery MACT 1 (40 CFR 63.654, 

Subpart CC) that we are finalizing in 

today’s action contains only two 

exemptions: one based on pressure 

differential and one for intervening 

fluid. The exemptions for ‘‘in HAP 

service’’ and small heat exchangers are 

not needed based on the revised 

definition of ‘‘heat exchange system.’’ 

These heat exchangers are not part of 

the affected heat exchange system as 

that term is defined in these final 

amendments. 

We are finalizing several technical 

and clarifying corrections in response to 

issues identified by public commenters. 

One of these amendments is in response 

to a commenter’s request for clarity on 

how delay of repair emissions are to be 

calculated and for confirmation that the 

emissions should be estimated for the 

period of time that the delay of repair 

occurred. The October 2009 standards 

required the calculation of emissions 

projected for the ‘‘expected duration of 

delay’’ using the monitored leak 

concentration. As the heat exchange 

system for which repair is delayed must 

be monitored monthly, we interpret the 

rule to require a monthly estimate of the 

emissions projected for the duration of 

the delay of repair. However, the 

reporting requirement is an estimate of 

the emissions that occur as a result of 

delayed repairs over the reporting 

period. As such, the owner or operator 

must actually calculate the emissions 

projected over each monitoring interval 

and sum these estimates for the period 

covered by the semi-annual report. 

Therefore, in order to better align the 

calculation, recordkeeping and 

reporting requirements, we have revised 

the requirement to develop a monthly 

emission estimate for ‘‘the duration of 

the expected delay of repair’’ to require 

calculation of emissions projected for 

‘‘each monitoring interval.’’ We also 

revised the recordkeeping requirements 

to keep records of these ‘‘monitoring 

interval’’ emission estimates, which can 

be directly used to develop the emission 

estimates required in the semi-annual 

reports. We are also clarifying that the 

delay begins on the date the leak would 

have had to be repaired had the repair 

not been delayed. We are revising the 

recordkeeping requirement for the 

‘‘identification of all heat exchangers at 

the facility’’ to instead require records 

for ‘‘identification of all petroleum 

refinery process unit heat exchangers at 

the facility’’ commensurate with our 

revision of the definition of ‘‘heat 

exchange system’’ and our desire to 

focus the Refinery MACT 1 heat 

exchange system requirements on heat 

exchangers associated with petroleum 

refinery process units. Finally, we are 

specifying that records related to the 

heat exchanger provisions be retained 

for 5 years, consistent with retention 

requirements for other emissions 

sources. 

Today’s final rule also addresses 10 

reconsideration issues raised by the API. 

The API requested an administrative 

reconsideration under CAA section 

307(d)(7)(B) of certain provisions of 40 

CFR part 63, subpart CC that they had 

identified in an April 7, 2009, letter to 

the EPA. As described in detail in the 

January 6, 2012, proposal (see 77 FR 

964), we denied API’s request for six of 

the reconsideration issues either 

because they were irrelevant after the 

subsequent withdrawal of the 

amendments to the Refinery MACT 1 

storage vessel requirements or because 

the issues could have been raised during 

the public comment period. We granted 

reconsideration on the following issues: 

(1) The use of the promulgation date to 

describe the applicability for new 

sources in 40 CFR 63.640(h)(1); (2) the 

definition of ‘‘heat exchange system’’ in 

40 CFR 63.641 as it relates to oncethrough heat exchange systems and 

refinery process units; (3) the 

monitoring procedures for once-through 

heat exchange systems in 40 CFR 

63.654(c); and (4) the determination of 

the cooling water flow rate in 40 CFR 

63.654(g). This final action reflects our 

reconsideration of issues raised in API’s 

request for reconsideration. 

IV. Summary of Comments and 

Responses 

A. Uniform Standards for Heat 

Exchange Systems 

On January 6, 2012, we proposed 

Uniform Standards for Heat Exchange 

Systems (40 CFR part 65, subpart L). We 

also proposed to remove most of the 

substantive requirements for heat 

exchange systems from Refinery MACT 

1, to include them in the Uniform 

Standards, and to cross-reference the 

Uniform Standards from Refinery 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37137 

MACT 1. We received numerous 

comments on the creation of Uniform 

Standards for Heat Exchange Systems 

and the proposed cross-referencing to 

the Uniform Standards within Refinery 

MACT 1 (40 CFR part 63, subpart CC). 

We are not taking final action to create 

Uniform Standards for Heat Exchange 

Systems at this time. We will address 

the comments that focused on the 

creation of the Uniform Standards in the 

context of future Uniform Standards 

regulatory actions. Section IV.B of this 

preamble addresses the comments 

regarding the substance of requirements 

that we proposed to include in the 

Uniform Standards but that we are now 

finalizing as part of Refinery MACT 1, 

or requirements proposed in the 

Uniform Standards that we have 

decided not to finalize as they would 

apply to heat exchange systems at 

refineries. 

B. Refinery MACT 1 Requirements for 

Heat Exchange Systems 

1. Definition of Heat Exchange System 

Comment: One commenter supported 

the proposed change to the definition of 

‘‘heat exchange system’’ that clarifies 

that heat exchangers need not be piped 

in series. 

Response: We appreciate support of 

this clarification. 

Comment: One commenter stated that 

including the cooling tower in the 

definition of ‘‘heat exchange system’’ 

means there can be only one heat 

exchange system per cooling tower, and 

this unduly complicates the rule 

(because the rule has to discuss 

requirements for individual exchangers 

and groups of exchangers as well as the 

heat exchange system). The commenter 

also suggested that the definition be 

limited to heat exchangers that serve 

petroleum refining process units to 

clarify that heat exchangers outside of 

the affected source are not subject to the 

Refinery MACT 1 requirements, which 

would be clearer than relying on the 

affected source description in 40 CFR 

63.640 to limit applicability. Another 

commenter stated that monitoring 

provisions in 40 CFR 63.654(a) should 

focus on heat exchangers that service 

refinery process units because there is 

no legal basis for applying the rule to 

heat exchangers that service 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, the 

regulatory language would still have to 

discuss heat exchangers, groups of heat 

exchangers and heat exchange systems 

to allow both centralized and separate 

monitoring of heat exchangers (or 

groups of heat exchangers). The 

flexibility provided in the monitoring 

locations, not the inclusion of the 

cooling tower, appears to be the primary 

source of complexity in the rule. As we 

allow monitoring of the cooling water at 

the cooling tower, it is logical that the 

cooling tower be part of the heat 

exchange system. Furthermore, the 

cooling tower is a central and essential 

part of a closed-loop heat exchange 

system for the system to operate 

properly. It is easily identifiable for 

permitting and enforcement personnel 

and it is the location at which most 

refineries are expected to perform the 

required monitoring. The cooling tower 

is also the location at which the 

strippable hydrocarbons are emitted. 

With respect to limiting the definition 

to heat exchangers that serve petroleum 

refining process units, we find that this 

comment has merit. Because Refinery 

MACT 1 is a NESHAP, in this final 

action, we intentionally limited repairs 

to heat exchangers that are ‘‘in organic 

HAP service.’’ The rule as finalized in 

2009 also limited applicability by 

defining as part of the affected source 

‘‘all heat exchange systems associated 

with refinery process units and which 

are in organic HAP service’’ in 40 CFR 

63.640(c)(8). While we expect most heat 

exchange systems at petroleum 

refineries to process cooling water from 

heat exchangers associated only with 

refinery process units, we recognize that 

there may be other process units at a 

refinery, particularly ethylene units and 

units subject to the National Emission 

Standards for Organic Hazardous Air 

Pollutants from the Synthetic Organic 

Chemical Manufacturing Industry (40 

CFR part 63, subpart F) (‘‘HON’’). 

We generally prefer not to include 

applicability criteria in emission source 

definitions, but recognizing the 

complexity of the current construct, we 

considered whether revising the 

definition of heat exchange system 

might increase the clarity of the 

monitoring and repair requirements for 

specific heat exchangers within the heat 

exchange system. Specifically, we 

considered defining a closed-loop heat 

exchange system as ‘‘a cooling tower, all 

petroleum refinery process unit heat 

exchangers serviced by that cooling 

tower that are in organic HAP service, 

as defined in this subpart, and all water 

lines to and from these petroleum 

refinery process unit heat exchangers.’’ 

The qualifications in this definition 

provide clarity that the repair 

requirements in 40 CFR 63.654 apply 

only to refinery process unit heat 

exchangers that are in organic HAP 

service; other heat exchangers that 

might be serviced by a common cooling 

tower are not part of the ‘‘heat exchange 

system.’’ A similar revision for oncethrough systems would be ‘‘all heat 

exchangers that are in organic HAP 

service, as defined in this subpart, 

servicing an individual petroleum 

refinery process unit and all water lines 

to and from these heat exchangers.’’ 

Considering the broad definition of 

‘‘petroleum refinery process unit’’ and 

the existing exclusions in 40 CFR 

63.640(g), we are finalizing these 

revisions to the definition of heat 

exchange system because we believe 

that these revisions clarify the intent of 

the requirements within Refinery MACT 

1 as finalized in October 2009 and limit 

the applicability of the repair 

requirements to individual heat 

exchangers servicing refinery process 

units. 

Comment: Two commenters suggested 

that all sample coolers and pump seal 

coolers should be specifically exempted 

from the monitoring requirements and/ 

or that the threshold in 40 CFR 

65.610(b)(3) should be raised from 10 

gallons per minute to 50 gallons per 

minute. The commenters stated that it 

was burdensome to have to evaluate the 

flow rate for every sample cooler at the 

refinery in order to assess the 

monitoring applicability and that 

sample coolers were not considered in 

the EPA analysis of heat exchange 

systems. 

Response: In the January 2012 

proposal, we included an exemption for 

very small heat exchange systems (those 

with water flow rates less than 10 

gallons per minute). This exemption 

was specifically targeted to exempt 

sample coolers and pump seal coolers 

because we did not consider these 

coolers significant sources of emissions 

and did not include them in our MACT 

floor and impacts analysis for the 

October 2009 final rule. We considered 

providing a higher flow exclusion to 

individual heat exchangers, but this 

would still require the refinery owners 

and operators to identify and assess the 

flow rates of each sample cooler. After 

reviewing the options, we have 

concluded that adding language to 

specifically exclude sample coolers and 

pump seal coolers from the definition of 

heat exchange system provides the 

clearest means to ensure that the 

regulations do not unintentionally 

capture these ‘‘coolers’’ that were not 

considered part of a ‘‘heat exchange 

system’’ in our original analysis and that 

we did not intend to be monitored 

under the Refinery MACT 1 regulations. 

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37138 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

See the new regulatory definition at 40 

CFR 63.641 for heat exchange system. 

Comment: One commenter suggested 

that the EPA define the term ‘‘strippable 

hydrocarbons’’ to mean the 

hydrocarbons measured by any of the 

methods specified in 40 CFR 

65.610(a)(3). 

Response: We considered providing a 

specific definition of ‘‘strippable 

hydrocarbons’’ in these final 

amendments, but the suggested 

definition is unnecessary since we are 

not finalizing the use of water methods 

as an alternative monitoring method for 

petroleum refineries. The monitoring 

method required by the regulations, the 

Modified El Paso Method, provides the 

best definition of strippable 

hydrocarbons as it relates to potential 

emissions from heat exchange systems. 

2. Applicability and Exemptions 

Comment: One commenter supported 

the proposed revisions clarifying the 

construction date criteria for defining a 

new source for the purpose of the heat 

exchange provisions. 

Response: We appreciate support of 

this clarification. 

Comment: One commenter 

recommended deleting the provision 

that limits once-through heat exchange 

systems to a single process unit because 

the MACT floor analysis does not 

support this approach. Although the 

process unit restriction is currently in 

40 CFR 63.641, the commenter noted 

that this language was not in the 

September 4, 2007, proposal or the 

November 10, 2008, supplemental 

proposal and, therefore, has not been 

subject to public comment until now. 

The commenter stated that, if the 

process unit restriction is maintained, 

the EPA should limit the rule to 

monitoring systems with a flow greater 

than 5,000 gallons per minute because 

the EPA’s analysis shows control for 

smaller systems is not cost effective. 

The commenter also suggested that the 

EPA’s analysis did not consider 

monitoring once-through systems 

individually. 

Response: Although the original 

MACT floor and impacts analysis (see 

the technical memorandum titled, 

‘‘Cooling Towers: Control Alternatives 

and Impact Estimates,’’ Docket Item No. 

EPA–HQ–OAR–2003–0146–0143) 

referred to ‘‘cooling towers’’ rather than 

‘‘heat exchange systems,’’ we believe the 

analysis adequately considered all heat 

exchange systems at all petroleum 

refineries. We projected the nationwide 

total number of ‘‘cooling towers’’ to be 

520 using information from the Texas 

Commission on Environmental Quality 

(TCEQ) for 50 petroleum refineries and 

extrapolating (considering capacity) to 

all U.S. petroleum refineries. Based on 

this analysis, every refinery was 

projected to have several ‘‘cooling 

towers’’ or ‘‘heat exchange systems’’ in 

our MACT floor and impacts analysis, 

and we assumed that refineries with 

once-through cooling systems would 

have a similar number of heat exchange 

systems (per refining capacity) as 

refineries with closed-loop (cooling 

tower) systems. We conducted analyses 

to determine how the number of cooling 

towers or heat exchange systems would 

affect our MACT floor calculations if 

there were more than our estimated 520. 

Because the monitoring and repair 

requirements for many of the bestperforming heat exchange systems were 

identical, we determined that the MACT 

floor requirements for existing sources 

would be the same even if there were as 

many as 666 affected ‘‘cooling towers’’ 

or ‘‘heat exchange systems’’ (see the 

technical memorandum titled, ‘‘Revised 

Impacts for Heat Exchange Systems at 

Petroleum Refineries,’’ Docket Item No. 

EPA–HQ–OAR–2003–0146–0230). 

To further verify our MACT floor 

calculations, we reviewed the 

information collected during the 

detailed information collection request 

(ICR) for petroleum refineries (see 

Docket Item Nos. EPA–HQ–OAR–2010– 

0682–0061 through 0069). The 

definition for heat exchange system in 

the ICR was identical to the definition 

in Refinery MACT 1 (with once-though 

systems limited to individual process 

units). Based on the ICR responses, 

there are 525 heat exchange systems that 

are in organic HAP service and that do 

not qualify for the exemption from 

monitoring based on higher water-side 

pressures; only 21 of these 525 are oncethrough 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 oncethrough systems) was reasonably 

accurate, and the existing source MACT 

floor monitoring requirements would 

not be impacted had we used the upper 

range estimate from the ICR data. As 

such, we disagree that our MACT floor 

analysis is inconsistent with the 

restriction of once-through systems to a 

single process unit. 

With respect to the suggestion that we 

limit the monitoring of closed-loop heat 

exchange systems to only those with 

flows of 5,000 gallons per minute or 

more, we note that closed-loop heat 

exchange systems that have flow rates 

less than 5,000 gallons per minute are 

common at refineries. These smaller 

heat exchange systems were included in 

our MACT floor and impacts analysis, 

and we did not subcategorize these heat 

exchange systems by size. The assertion 

that monitoring these smaller heat 

exchange systems is not cost effective is 

not relevant; we do not consider costs 

in developing the MACT floor 

requirements. We only consider costs 

when evaluating alternatives beyond the 

MACT floor. As described previously, 

we believe we adequately considered 

the total number of affected heat 

exchange systems (including oncethrough and small heat exchange 

systems) when establishing the MACT 

floor requirements for existing sources. 

We noted in the January 2012 

proposal that: ‘‘A once-through heat 

exchange system could include all heat 

exchangers at the entire facility. The 

potential to aggregate all cooling water 

at a facility (as opposed to a single 

process unit) prior to sampling for a 

once-through system would greatly 

reduce the effectiveness of the leak 

monitoring methods and would allow 

HAP or VOC leaks to remain 

undetected, based solely on the dilution 

effect from the vast quantity of water 

processed at the facility.’’ (See 77 FR 

967). We specifically requested 

comment on how we might allow some 

aggregation across units but not allow 

dilution across all units at the plant. 

The commenter did not provide any 

suggestions on this point, but rather 

suggested that if aggregation were not 

allowed, once-through heat exchange 

systems with flow less than 5,000 

gallons per minute should be excluded. 

For closed-loop heat exchange 

systems, there are physical limitations 

on the cooling tower that limit the 

number of units that can be serviced by 

the cooling tower. Again, our analysis 

suggested there would be several heat 

exchange systems per refinery compared 

to a single heat exchange system for 

once-through systems. On the other 

hand, we recognize that the definition of 

‘‘heat exchange system’’ in the October 

2009 final rule limits aggregation for 

refineries operating once-through 

systems more than refineries that 

operate closed-loop systems. Therefore, 

we evaluated several ways to afford 

some aggregation for once-through heat 

exchange systems so that these systems 

would be more comparable to the 

‘‘cooling tower’’ heat exchange systems 

identified in the MACT floor 

memorandum (Docket Item No. EPA– 

HQ–OAR–2003–0146–0143). We 

identified no appropriate way to allow 

some, but constrained aggregation 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37139 

across process units within the 

definition of heat exchange system. 

Therefore, we are not modifying the 

definition of ‘‘heat exchange system’’ as 

it relates to once-through systems (i.e., 

a once-through heat exchange system is 

still limited to the heat exchangers 

associated with a single refinery process 

unit). As an alternative, we evaluated 

allowing monitoring for once-through 

cooling systems at locations that include 

cooling water from several heat 

exchange systems. Based on the 

responses from the detailed ICR, 

approximately 90 percent of all cooling 

towers (i.e., closed-loop heat exchange 

systems) at petroleum refineries have 

flow rates of 40,000 gallons per minute 

or less. As such, we consider that this 

90th percentile value provides a 

reasonable proxy of the upper level of 

aggregation provided to facilities with 

closed-loop heat exchange systems. By 

allowing once-through heat exchange 

systems to monitor at locations that 

include cooling water from several heat 

exchange systems, provided that the 

combined cooling water flow rate at the 

monitoring location does not exceed 

40,000 gallons per minute, we are 

providing a means to aggregate across 

process units in a manner similar to that 

afforded to closed-loop heat exchange 

systems, which is the assumption made 

in our MACT floor and impacts 

analyses. As this level of aggregation is 

similar to that for closed-loop heat 

exchange systems, we expect that this 

provision will achieve the same 

emission reductions at the same costs as 

projected for our model closed-loop heat 

exchange systems. We also note that this 

approach is preferable to the suggested 

exemption for all once-through heat 

exchange systems below 5,000 gallons 

per minute because it achieves greater 

emission reductions at similar costs. 

Therefore, we have amended the 

monitoring location for once-through 

heat exchange systems to allow 

monitoring at a point where discharges 

from multiple heat exchange systems 

are combined, provided that the 

combined cooling water flow rate at the 

monitoring location does not exceed 

40,000 gallons per minute. 

Comment: Several commenters stated 

that the EPA should retain the 

exemption for heat exchange systems 

that have an intervening cooling fluid 

that contains less than 5 percent by 

weight of HAP. 

Response: This exemption was 

included in the October 2009 final 

standards for refinery heat exchange 

systems and it was our intent to retain 

this existing exemption for petroleum 

refineries. However, when the heat 

exchange system Uniform Standards 

were proposed, we inadvertently 

omitted a cross-reference to this 

exemption from Refinery MACT 1. As 

noted previously, we are not 

promulgating the Uniform Standards or 

the cross-references to the Uniform 

Standards from Refinery MACT 1. The 

provision to exempt heat exchange 

systems that use an intervening fluid 

that is less than 5 percent by weight 

HAP is retained as a part of Refinery 

MACT 1. 

Comment: One commenter suggested 

that the introductory paragraph in 40 

CFR 65.610(b) should specify that 

engineering judgment may be used to 

determine whether any of the 

exemption criteria are met. 

Response: As noted in section III of 

this preamble, heat exchangers may be 

excluded from a ‘‘heat exchange 

system’’ based on differential pressure 

or the presence and content of an 

intervening fluid. We did not specify 

that engineering judgment can be used 

for the differential pressure exemption, 

either in the October 2009 final rule or 

the January 2012 proposed 

amendments. We expect that direct 

pressure measurements of the process 

fluids and cooling water lines will be 

made in a representative location at 

which the pressure exclusion can be 

documented. With respect to the 

intervening fluid exemption, we 

intended that the same requirements 

used to determine ‘‘in organic HAP 

service’’ would apply to the intervening 

fluid. We revised the description of this 

exemption to specify that the provisions 

of 40 CFR 63.180(d) of subpart H should 

be used; 40 CFR 63.180(d) allows the 

use of ‘‘good engineering judgment’’ 

under most circumstances. 

3. Compliance Date 

Comment: One commenter suggested 

that the compliance date be reset to be 

at least 1 year after the promulgation 

date of the final amendments to provide 

time for the refineries to develop 

procedures for complying with the 

proposed options and any other changes 

made in response to public comments. 

Response: Petroleum refinery owners 

and operators have been on notice of the 

October 29, 2012, compliance date since 

promulgation of the heat exchange 

standards in October 2009. Refinery 

owners and operators that follow the 

requirements in the October 2009 final 

rule will be in compliance with these 

final amendments. If a facility elects to 

change to quarterly monitoring at the 

lower leak definition, there are 

provisions in the final amendments for 

how this change can be made. 

Therefore, there is no need to reset the 

compliance date. 

4. Monitoring Locations and Analytical 

Methods 

Comment: Several commenters 

requested that a leak be determined 

based on the difference between inlet 

and outlet concentrations. One 

commenter specifically noted that the 

EPA should reconsider this approach, 

which is used in the Hazardous Organic 

NESHAP (‘‘HON’’; 40 CFR part 63 

subpart F), for refinery heat exchange 

systems. The commenter disputed the 

EPA claims that accumulating 

hydrocarbons in the cooling water are 

evidence of a leak and that small leaks 

are cost effective to repair, stating the 

build-up of organic chemicals can be 

caused by the use of chemical additives 

for corrosion or biological growth 

prevention and these heavy compounds 

are not stripped in the cooling tower as 

completely as they are in the Modified 

El Paso Method stripping column. 

Response: The rule does not provide 

for the use of inlet and outlet sampling 

for closed-loop heat exchange systems 

because the MACT floor requirements 

for heat exchange systems were based 

on existing monitoring of the cooling 

water return line only. If the rule 

allowed the use of a concentration 

differential, it would be less stringent 

than the MACT floor because the MACT 

floor monitoring was not based on a 

differential concentration, but the direct 

concentration in the cooling water 

return line. Although we expect that the 

strippable hydrocarbons measured by 

the Modified El Paso Method will be 

largely removed (i.e., released to the air) 

in the cooling tower so that the cooling 

water inlet to the heat exchangers will 

have limited concentrations of 

strippable hydrocarbons, it is unlikely 

that this concentration would be exactly 

zero. Therefore, using a concentration 

differential produces a concentration 

that has been adjusted to account for 

hydrocarbons still in the water after the 

cooling tower, and is lower and 

therefore less likely to trigger the leak 

definition. We did not allow this option 

for closed–loop heat exchangers. The 

rule does provide for the use of inlet 

and outlet sampling for once-through 

heat exchange systems. While we have 

taken the position that once-through 

heat exchange systems have a similar 

emission potential as closed-loop 

systems, we acknowledge that these 

systems are different in operation and 

that contaminants may be present in the 

pond, river or other source of 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 

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37140 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

allow a concentration differential to be 

used to determine a leak for oncethrough heat exchange systems. 

Comment: One commenter noted that 

the requirements in 40 CFR 65.610(e) 

are unnecessarily burdensome because 

they require a source to monitor all heat 

exchangers to find a leak and they 

appear to require continued monthly 

testing of all heat exchangers even if the 

leak is not from an exchanger that is 

subject to the repair requirements. This 

commenter also recommended simply 

requiring the leaking exchanger to be 

identified by the most expeditious 

process and then requiring repair only 

if the leaking exchanger is in service 

associated with a referencing subpart. 

Response: The cited provisions do not 

require monitoring of all affected heat 

exchangers to find a leak. The refinery 

owner or operator can use any method 

they choose to identify the leaking heat 

exchanger. If the identified leaking heat 

exchanger is not in HAP service, then 

the refinery owner or operator has two 

options: (1) fix the leak and continue to 

monitor in the main cooling tower 

return line or (2) demonstrate that all 

heat exchangers within the heat 

exchange system that are subject to the 

monitoring and repair provisions are not 

leaking by monitoring each heat 

exchanger or group of heat exchangers 

subject to the repair provisions. Thus, 

the option of monitoring each heat 

exchanger or group of heat exchangers 

is not required to identify the leaking 

heat exchanger; rather, this monitoring 

option is provided only for the case in 

which the refinery owner or operator 

elects not to fix a leak that was 

identified through monitoring of the 

cooling tower return line on the grounds 

that the leaking heat exchanger is not 

subject to the repair provisions in 

Refinery MACT 1. 

Comment: One commenter suggested 

that the monitoring frequency/leak 

definition alternatives for existing 

sources should be allowed on an 

individual or group of heat exchangers 

basis as well as on a heat exchange 

system basis. 

Response: The rule allows monitoring 

at the individual heat exchanger (or 

group of heat exchangers) level or at the 

heat exchange system level (i.e., 

monitoring at the cooling tower). 

However, in order to allow this 

flexibility for either aggregate or 

individual monitoring to be performed 

without any notification to the EPA, all 

heat exchangers that are part of a heat 

exchange system must use the same 

monitoring frequency and leak 

definition. We considered allowing the 

suggested alternative for individual heat 

exchangers within a heat exchange 

system, but concluded that it would 

likely result in uncertainty regarding 

what compliance monitoring, reporting 

and recordkeeping requirements would 

be required for individual heat 

exchangers. As the affected facility is 

the heat exchange system, we consider 

it appropriate that the same monitoring 

frequency and leak definition be used 

for all monitoring locations within one 

heat exchange system. The final rule 

clearly allows (in 40 CFR 63.654(c)(4)) 

the owner or operator of existing 

sources to use the alternative quarterly 

monitoring option for some heat 

exchange systems and the monthly 

monitoring option for others but all heat 

exchangers or groups of heat exchangers 

within a single heat exchange system 

must use the same monitoring frequency 

and leak definition. 

Comment: Two commenters noted 

that section 5.1.1.4 of the Modified El 

Paso Method specifies that samples 

must be drawn from a location prior to 

the risers. The commenter requested 

clarification that monitoring may 

instead be conducted either prior to the 

risers or in any individual riser because 

the concentration of hydrocarbons is 

distributed equally to each riser and the 

system has no openings to the 

atmosphere prior to discharge into the 

cooling tower cells. They also noted that 

refineries often monitor in a riser and 

changes needed to enable monitoring 

prior to the riser would require a 

significant capital expenditure. 

Response: The final amendments 

describe monitoring locations specific 

for Refinery MACT 1 and then 

separately describes the allowed 

monitoring methods. Reference to the 

Modified El Paso Method is confined to 

the monitoring method section of 

Refinery MACT 1, and the Modified El 

Paso Method’s restriction on sampling 

in the riser is not applicable. 

Nonetheless, we have provided specific 

clarifications in the monitoring location 

section that monitoring in the cooling 

tower riser (prior to exposure to the 

atmosphere) is allowed. 

Comment: One commenter stated that, 

in addition to a flame ionization 

detector, the EPA should allow use of 

other detectors, such as a photo 

ionization detector or mass 

spectrometry and online gas 

chromatograph (GC) capable of 

equivalent sensitivity for target 

compounds when using the Modified El 

Paso Method. 

Response: We specifically require the 

stripping gas concentration to be 

determined in ppmv as methane. While 

a refinery owner or operator may elect 

to use a GC and other analyzers to 

speciate the compounds present in the 

cooling water in order to identify the 

specific heat exchangers or group of 

heat exchangers responsible for the leak, 

the leak itself must be determined using 

a flame ionization detector calibrated 

with methane following the procedures 

in section 6.1 of the Modified El Paso 

Method. As discussed in further detail 

in the following comment and response, 

we find that speciated analysis of target 

compounds in the stripping gas is likely 

to result in incomplete characterization 

of the total hydrocarbon concentration 

and could be less stringent than the 

MACT floor determined for petroleum 

refinery heat exchange systems. We 

have further clarified this requirement 

in these final amendments by 

specifically referencing section 6.1 of 

the Modified El Paso Method. However, 

this requirement does not preclude the 

refinery owner or operator from 

conducting additional analysis of the 

stripping gas as a means to identify the 

leaking heat exchanger. 

Comment: Several commenters 

requested that the rule allow additional 

measurement methods in order to 

characterize the compounds that could 

leak into the cooling water. The 

measurement methods suggested 

include EPA Method 624 of Appendix 

A to 40 CFR part 136 and SW–846 

Methods 8270 and 8315. Commenters 

also stated that characterizing all 

volatile compounds (or even all volatile 

organic HAP) is often impossible due to 

the high number of compounds that 

may be in a process stream, and it is not 

necessary, as detection of key 

compounds from the process is all that 

is needed to identify a leak. One 

commenter suggested that this rule 

should be like the TCEQ’s rule that 

requires characterization of compounds 

with boiling points less than 140 

degrees Fahrenheit (°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 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 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37141 

in a petroleum refinery process stream. 

While we considered including 

additional test methods, the inclusion of 

additional test methods did not appear 

to address the primary issue regarding 

the ability to fully characterize the 

compounds that could leak into the 

cooling water. We disagree that the 

characterization of compounds should 

be limited to compounds with boiling 

points less than 140 °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 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 to fully characterize the 

pollutants that could leak into the 

wastewater would include all 

compounds, even those that may not be 

effectively stripped in the stripping 

column (or cooling tower). Options to 

limit the full characterization 

requirement call into question the 

ability of the water methods to be as 

stringent as the total strippable 

hydrocarbon analysis using the 

Modified El Paso Method. 

In light of the complexity of most 

petroleum refinery process streams, we 

are concerned that there may be a leak 

that exceeds 40 parts per billion by 

weight (ppbw) total strippable 

hydrocarbons in the water-phase as 

determined by back-calculation from the 

Modified El Paso Method results, but 

because of the number of different 

compounds present in the petroleum 

refinery stream (often on the order of 50 

to 100 different compounds), the 

concentrations of the individual 

compounds could all be below the 

analytical detection limit (typically 

about 5 to 10 ppbw in the cooling 

water). In such a case, the water 

methods, even with low detection 

limits, may not provide a suitable 

alternative to the Modified El Paso 

Method for refinery heat exchange 

systems. 

To further evaluate our concerns 

regarding the use of water measurement 

methods for refinery heat exchange 

systems, we reviewed the source test 

data received in response to the cooling 

water testing required as part of the 

detailed information collection request 

for petroleum refineries. We compared 

the stripping column gas sampling 

results with those from the direct water 

methods (see the memorandum titled, 

‘‘Evaluation of the Refinery ICR Cooling 

Water Analysis Results’’ in Docket ID 

No. EPA–HQ–OAR–2003–0146). We 

found that the analytical methods for 

chemical species (in both stripping gas 

analysis and water samples) greatly 

underestimated the overall 

concentrations of hydrocarbons, 

primarily because these analyses were 

conducted using a specific target analyte 

list. As the water methods (or gas-phase 

speciated analysis methods) generally 

include a specific list of target analytes, 

we now expect that these methods 

could lead to less effective leak 

identification. 

We considered the alternative of 

monitoring a specific compound and 

extrapolating that compound 

concentration to determine a total 

strippable hydrocarbon concentration, 

but we determined that this approach 

generally would be more complicated 

and burdensome than direct Modified El 

Paso monitoring, given the complexity 

of petroleum refinery process fluids and 

the likelihood that several different heat 

exchangers (with process fluids of 

differing compositions) may be serviced 

by a single cooling tower (i.e., heat 

exchange system). We see no easy way 

to specify ‘‘a general procedure for 

monitoring surrogate species or 

indicator species’’ while ensuring 

equivalency with the Modified El Paso 

Method. One would need to use the 

Modified El Paso Method to develop the 

extrapolation factor for each process 

fluid that could potentially leak into the 

cooling water and to verify that the 

method used provides adequate 

detection limits. This would be difficult 

to do and complex, considering the 

potential variation in compounds and 

concentrations across process streams. 

Given the complexity of most 

petroleum refinery process streams, we 

were unable to identify from the 

currently available water methods a 

method that would be suitable for 

determining the total strippable 

hydrocarbon concentration with the 

accuracy and sensitivity needed to be 

comparable to the Modified El Paso 

Method. Therefore, we are not finalizing 

any alternative water methods for 

monitoring petroleum refinery heat 

exchange systems. 

Comment: Several commenters 

requested that the rule allow 

measurement of surrogates. One 

commenter requested inclusion of the 

full spectrum of monitoring methods 

currently listed in the HON, the 

National Emission Standards For 

Ethylene Manufacturing Process Units: 

Heat Exchange Systems And Waste 

Operations (40 CFR part 63, subpart XX) 

(‘‘Ethylene NESHAP’’), and the online 

monitoring for ethylene and propylene 

that is allowed in TCEQ HRVOC Rule 

(TAC Title 30 Part I Chapter 115 Div. 2 

§ 115.764). One commenter noted that 

the proposed methods would require 

most facilities to use offsite test 

resources, but other methods, 

particularly if surrogates can be 

measured, would allow sites to conduct 

analyses themselves and respond more 

quickly to any leaks. 

Response: We disagree with the 

comments suggesting all measurement 

methods provided in the HON, the 

Ethylene NESHAP or the TCEQ rules 

should be allowed. The leak definition 

for petroleum refineries is lower than 

specified in those rules. In our revised 

impacts analysis for the proposed 

amendments(see the technical 

memorandum titled, ‘‘Revised Impacts 

for Heat Exchange Systems at Petroleum 

Refineries,’’ Docket Item No. EPA–HQ– 

OAR–2003–0146–0230), the leak 

detection level was generally the most 

important parameter influencing the 

effectiveness of the heat exchange 

system monitoring program. We 

evaluated a series of ‘‘surrogate’’ 

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methods when evaluating different heat 

exchange system monitoring 

alternatives for the October 2009 final 

rule and concluded that these surrogate 

methods were not as effective as 

identifying leaks as the Modified El 

Paso Method. 

We acknowledge that the proposed 

water method alternatives would often 

require the use of external laboratories; 

however, as discussed previously, we 

are not finalizing the proposed water 

method alternatives. The Modified El 

Paso Method, on the other hand, is 

performed on-site. The method is 

relatively simple and can be operated by 

refinery personnel or outside 

contractors to provide immediate leak 

monitoring results, so it has the same 

advantages of the ‘‘surrogate’’ methods 

while also being able to detect small 

leaks. 

Comment: One commenter requested 

that sources be allowed up to 7 calendar 

days for re-monitoring a heat exchange 

system to verify repair when a repaired 

heat exchanger is returned to service 

either after the end of the 45-day normal 

repair window (as long as the heat 

exchanger was taken out of service 

before the end of that 45-day window) 

or after an allowed delay of repair 

period. The commenter noted that if the 

heat exchanger is taken out of service as 

the means of repair and then brought 

back into service after the 45-day 

window, then additional time is needed 

to start up, line-out, and retest that heat 

exchanger. 

Response: In the January 2012 

proposal, we proposed to clarify that 

under the existing MACT standard, 

‘‘repair’’ includes verification that the 

actions taken to repair the leak were 

effective through re-monitoring of the 

heat exchange system. We consider the 

45-day repair window for a typical 

repair as well as the additional time 

provided for a delayed repair to be 

adequate considering the time necessary 

to re-monitor the heat exchange system. 

We expect that repairs will be made as 

expeditiously as possible and that the 

actions will be taken with sufficient 

time to confirm the repairs within the 

45-day repair window. Refinery MACT 

1 specifically allows the use of 

removing a heat exchanger from service 

as a means to effect repair in 40 CFR 

63.654(d)(5). The heat exchange system 

would need to be re-monitored within 

the 45-day window to verify that the 

removal of the heat exchanger 

effectively reduced the total 

hydrocarbons in the cooling water to 

below the leak threshold levels. In this 

case, the removal of the heat exchanger 

from service would accomplish the 

repair and the owner or operator could 

revert back to their chosen monitoring 

frequency. 

The rule is silent on a special 

monitoring event for the case in which 

the removed heat exchanger is 

subsequently placed back into service. 

This case is similar to the case where a 

new heat exchanger (or group of heat 

exchangers) is added to an existing heat 

exchange system. We interpret the rule 

to require only the routine heat 

exchange system monitoring with no 

special monitoring event required when 

adding these ‘‘new’’ heat exchangers to 

the heat exchange system. We anticipate 

that any ‘‘new’’ or ‘‘repaired’’ heat 

exchanger would be properly pressure 

tested prior to being placed in service. 

As such, these heat exchangers would 

be unlikely to leak, so the routine 

monitoring frequency is considered 

sufficient. We also note that, if an owner 

or operator removes a heat exchanger 

from service as a means to effect a 

repair, but then returns the same heat 

exchanger to service without any 

modification or repair, that owner or 

operator could be subject to potential 

enforcement actions for not complying 

with the operating and maintenance 

requirement ‘‘. . . to maintain any 

affected source . . . in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions’’ as required in 

the General Provisions at 40 CFR 

63.6(e). 

5. Delay of Repair 

Comment: One commenter suggested 

allowing delay of repair until the next 

scheduled process shutdown if the 

source opts to strip hydrocarbon from 

the cooling water and either recover it 

(as fuel or for process use) or collect and 

convey it to combustion control. 

Response: Provided that the stripped 

gases are properly captured and 

controlled, the current provisions would 

not exclude these actions as a means of 

compliance. The rule only lists those 

repair actions that are most likely to 

occur but we explicitly indicate that the 

list of repair actions is not all inclusive. 

If the actions described by the 

commenter reduce the concentration of 

strippable hydrocarbons to below the 

applicable leak action levels while 

preventing the release of those 

hydrocarbons to the atmosphere, we 

consider that these actions qualify 

under 40 CFR 63.654(d) as a repair, in 

which case the delay of repair would 

not be needed. 

If the actions described by the 

commenter do not reduce the strippable 

hydrocarbon concentration to below the 

leak action level, the existing delay of 

repair provisions, if applicable, can be 

used to continue operating until the 

next scheduled shutdown. In this case, 

the actions described by the commenter 

could be used to help prevent an 

exceedance of the delay of repair action 

level and thereby maintain the delayed 

repair. However, if the leak ever exceeds 

the delay of repair action level, the 

owner or operator could not use these 

actions merely to reduce the strippable 

concentration to below the delay of 

repair action level. Once the delay of 

repair threshold is exceeded, the owner 

or operator of the affected heat exchange 

system must repair the source within 30 

days by reducing the strippable 

hydrocarbon concentration to below the 

leak action level. 

Comment: One commenter requested 

confirmation that the guidelines given 

in TCEQ’s Sampling Procedures 

Manual, Appendix P, paragraph 7.2 

should be used for determining the 

molecular weight to use in equation 7.1 

of the Modified El Paso Method when 

determining potential emissions during 

a delayed repair. 

Response: The TCEQ’s Sampling 

Procedures Manual, Appendix P, is the 

Modified El Paso Method that is 

incorporated by reference in the heat 

exchange system provisions of Refinery 

MACT 1. In 40 CFR 63.654(g)(4), we 

specifically indicate that the stripping 

air concentration must be converted to 

a water concentration using Equation 7– 

1 of the Modified El Paso Method. 

Paragraph 7.2 of the Modified El Paso 

Method specifically notes that ‘‘[f]or 

total VOC based on the portable FID 

analyzer procedure in Section 6.1, 

calculate total VOC concentration in the 

water and emission rate based on the 

molecular weight of methane . . .’’ We 

specifically require the use of the 

stripping gas concentration to be 

determined using flame ionization 

detector (FID), as noted in section 6.1 of 

the Modified El Paso Method, calibrated 

with methane (‘‘as methane’’). 

Therefore, the molecular weight of 

methane (16 grams per mole) should be 

used when determining the equivalent 

water concentration using Equation 7–1 

of the Modified El Paso Method when 

calculating the potential strippable 

hydrocarbon emissions for a delayed 

repair. We have clarified this 

requirement in these final standards. 

6. Reporting and Recordkeeping 

Provisions 

Comment: One commenter requested 

clarification that the requirement to 

record water flow rates applies only to 

monitoring events in which a leak is 

detected and the equipment is placed on 

delay of repair because this is the only 

occasion in which flow rates are 

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needed. Another commenter stated that 

records of water flow and emissions 

estimates should be required only if the 

rule allows delay of repair based on a 

demonstration that the emissions 

caused by delaying repair are less than 

the emissions caused by a process unit 

shutdown, if needed, to effect the repair 

because this is the only situation where 

water flow and emissions are relevant. 

If these requirements are not deleted, 

one of the commenters stated that the 

EPA should clarify that the 

recordkeeping requirement is an 

estimate of ‘‘potential strippable 

hydrocarbon emissions’’ instead of 

‘‘potential emissions’’ because the latter 

might be misinterpreted to mean organic 

HAP emissions, which are only a 

fraction of the hydrocarbon emissions. 

In addition, a commenter stated that the 

EPA should clarify that reporting of ‘‘an 

estimate of total strippable hydrocarbon 

emissions for each delayed repair over 

the reporting period’’ covers only the 

time period from the date by which 

repair would have had to be completed 

if it were not delayed until the repair 

was completed. 

Response: The October 2009 final rule 

requires a record of the cooling water 

flow rate for each monitoring event. 

However, the commenter correctly notes 

that the requirement in 40 CFR 

63.654(g)(4)(ii) to determine the flow 

rate of cooling water only applies during 

periods in which repair is delayed. As 

such, we agree with the commenter that 

the regulations should not require 

records of the cooling water flow rate for 

all cooling towers or heat exchangers 

because the flow rate only needs to be 

determined for heat exchange systems 

for which repair is delayed. Therefore, 

we are moving the requirement to keep 

a record of the cooling water flow rate 

to the paragraph that is limited to 

delayed repairs, which is 40 CFR 

63.655(i)(4)(v) in today’s final rule. 

We disagree that recordkeeping and 

reporting of flow rate and potential 

emissions should only be required 

where emission caused by delay of 

repair are demonstrated to be less than 

they otherwise would be during a 

shutdown. Stakeholders including the 

public should be made aware of the 

potential air emissions releases that may 

occur based on the decision to delay 

repair. 

We agree that the phase ‘‘potential 

strippable hydrocarbon emissions’’ 

more accurately describes the delay of 

repair emission estimate than the phrase 

‘‘potential emissions’’ and we are 

clarifying the language as suggested by 

the commenter. Specifically, we are 

revising ‘‘potential emissions’’ to 

instead read ‘‘potential strippable 

hydrocarbon emissions’’ in the heat 

exchange system requirements at 40 

CFR 63.654(g)(4), the reporting 

requirements at 40 CFR 63.655(g)(9)(v) 

and the recordkeeping requirements at 

40 CFR 63.655(i)(4)(v) in today’s final 

rule. 

As described previously in section III 

of this preamble, today’s final rule 

requires that these emission estimates 

be determined for each monitoring 

interval instead of over the ‘‘expected 

duration of the delay.’’ To address the 

commenter’s concern, we are specifying 

in 40 CFR 63.654(g)(4)(iii) that ‘‘The 

duration of the delay of repair 

monitoring interval is the time period 

starting at midnight of the day of the 

previous monitoring event or midnight 

of the day the repair would have had to 

be completed if the repair had not been 

delayed, whichever is later, . . .’’ Given 

this clarification in the start of the delay 

of repair interval and the coordination 

between the emission estimate 

methodology and reporting 

requirements, we do not believe that 

additional language is needed in 40 CFR 

63.655(g)(9)(v) to further clarify that the 

delay of repair starts at the end of the 

45-day period provided to complete a 

repair under normal circumstances. 

Comment: One commenter requested 

clarification of the term ‘‘original date’’ 

in the reporting requirements in 40 CFR 

63.655(g)(9)(v) for delayed repair. 

Response: We are clarifying this 

regulatory provision by revising the 

phrase ‘‘original date’’ to instead say 

‘‘date when the delay of repair began.’’ 

As noted in the clarified language 

regarding the calculation of potential 

emissions during a delayed repair, the 

date the delay of repair began is 

equivalent to the day the repair would 

have had to be completed if the repair 

had not been delayed. 

Comment: One commenter stated that 

the proposed requirements to identify 

the ‘‘measured or estimated average 

annual regulated material concentration 

of process fluid or intervening cooling 

fluid processed in each heat exchanger’’ 

will be a very burdensome and 

unnecessary ongoing requirement rather 

than one-time requirement as specified 

in 40 CFR 63.655(i)(4)(i). 

Response: We agree that we should 

retain this as a one-time requirement. 

We did not intend to make this an 

ongoing requirement. The revised 

language cited by the commenter was 

part of the proposed Uniform Standards, 

which we proposed to cross-reference 

from Refinery MACT 1 but are not 

finalizing in this action. We are not 

revising the ‘‘one-time’’ requirement as 

specified in 40 CFR 63.655(i)(4)(i). 

Comment: One commenter suggested 

deleting paragraphs (b) and (c) in 40 

CFR 65.620 (i.e., reporting the number 

of heat exchange systems in regulated 

material service found to be leaking and 

the summary of the monitoring data that 

indicate a leak) because they duplicate 

the information required by paragraph 

(d) (i.e., reporting the date a leak was 

identified, the date the source of the 

leak was identified and the date of 

repair) or are unnecessary. 

Alternatively, the commenter suggested 

that the EPA should at least revise 40 

CFR 65.620(b) to require reporting of the 

number of leaking heat exchangers 

rather than heat exchange systems, and 

revise 40 CFR 65.620(c) to clarify what 

monitoring data to report and eliminate 

the redundancy. 

Response: The comments refer to the 

reporting and recordkeeping provisions 

that we proposed to codify as part of the 

Uniform Standards, which we are not 

finalizing in this action. The similar 

provisions in Refinery MACT 1, which 

we are retaining rather than crossreferencing the Uniform Standards, as 

proposed, are the reporting provisions 

in 40 CFR 63.655(g)(9)(ii) through (iv). 

We disagree with the commenter that 

there is undue overlap in these 

provisions. The number of heat 

exchange systems at the plant site found 

to be leaking (40 CFR 63.655(g)(9)(ii)) 

provides a useful summary to the report 

review. Analogous to the number of 

fugitive components found to be leaking 

over a semiannual period, which is also 

required to be reported under Refinery 

MACT 1, this information is an 

indicator of both leak program 

effectiveness and the refinery’s 

operating and maintenance practices. 

While one could count each entry in the 

list of leaking heat exchange systems 

required in 40 CFR 63.655(g)(9)(iii), we 

do not consider this duplicative of the 

list. We do agree that the ‘‘summary of 

monitoring data’’ could be more clearly 

delineated. To address this concern, we 

have revised the provisions in 40 CFR 

63.655(g)(9)(iii) to specifically list the 

desired reporting elements. We also 

consolidated some of the reporting 

elements from 40 CFR 63.655(g)(9)(iv) 

into 40 CFR 63.655(g)(9)(iii) and revised 

40 CFR 63.655(g)(9)(iv) to focus on 

reporting elements for leaks that were 

repaired during the reporting period. 

These reporting requirements are now 

more clear and distinct with no 

duplication. 

Comment: One commenter noted that 

it would be burdensome to identify, 

characterize or include pump seal 

coolers and sample coolers in the heat 

exchanger inventory and applicability 

determination. The commenter stated 

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37144 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

that there is no need for this 

requirement because those that are 

once-through coolers should be 

presumed to meet the low flow 

exemption criteria and those that are 

part of a recirculating system with large 

heat exchangers would be effectively 

regulated by monitoring of the cooling 

tower return lines. 

Response: We never intended to 

require monitoring of sample coolers 

and pump seal coolers. As discussed 

previously, sample coolers and pump 

seal coolers are specifically excluded 

from the definition of heat exchange 

system in today’s final rule, so these 

coolers do not have to be identified as 

part of the heat exchange system 

recordkeeping provisions. 

V. Summary of Impacts 

These final amendments will have no 

cost, environmental, energy or economic 

impacts beyond those impacts presented 

in the October 2009 final rule for heat 

exchange systems at petroleum 

refineries. If the owner or operator of an 

existing petroleum refinery elects the 

quarterly monitoring alternative at the 

lower leak definition or if the owner or 

operator of a once-through system can 

aggregate flows across process unit 

boundaries, we anticipate that the 

facility will realize a net cost savings 

compared to the costs estimated for the 

October 2009 final rule. All other 

amendments are projected to be 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 

recommendations have been 

documented in the docket for this 

action. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. The final 

amendments are clarifications and 

technical corrections that do not affect 

the estimated burden of the existing 

rule. Therefore, we have not revised the 

information collection request for the 

existing rule. However, OMB has 

previously approved the information 

collection requirements contained in the 

existing rule (40 CFR Part 63, subpart 

CC) under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501, et seq., and has assigned OMB 

control number 2060–0340. The OMB 

control numbers for the EPA’s 

regulations are listed in 40 CFR Part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities (SISNOSE). 

Small entities include small businesses, 

small organizations and small 

governmental jurisdictions. 

For the purposes of assessing the 

impacts of this final rule on small 

entities, small entity is defined as: (1) A 

small business that meets the Small 

Business Administration size standards 

for small businesses at 13 CFR 121.201 

(a firm having no more than 1,500 

employees); (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this final rule on small 

entities, I certify that this action will not 

have a SISNOSE. In determining 

whether a rule has a SISNOSE, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities.’’ 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule 

will not have a SISNOSE if the rule 

relieves regulatory burden, or otherwise 

has a positive economic effect on all of 

the small entities subject to the rule. 

Based on our economic impact 

analysis, the amendments will have no 

direct cost impacts (or they will result 

in a nationwide net cost savings). No 

small entities are expected to incur 

annualized costs as a result of the final 

amendments; therefore, no adverse 

economic impacts are expected for any 

small or large entity. Thus, the costs 

associated with the final amendments 

will not result in any ‘‘significant’’ 

adverse economic impact for any small 

entity. We have, therefore, concluded 

that today’s final rule will relieve 

regulatory burden for all affected small 

entities. 

D. Unfunded Mandates Reform Act 

This rule does not contain a federal 

mandate that may result in expenditures 

of $100 million or more for state, local 

and tribal governments, in the aggregate, 

or to the private sector in any one year. 

As discussed earlier in this preamble, 

these amendments are cost neutral and 

may result in net cost savings for the 

private sector. Thus, this rule is not 

subject to the requirements of sections 

202 or 205 of the Unfunded Mandates 

Reform Act (UMRA). 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. The 

final amendments contain no 

requirements that apply to such 

governments, and impose no obligations 

upon them. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. These final 

amendments do not add new control 

and performance demonstration 

requirements. They do not modify 

existing responsibilities or create new 

responsibilities among EPA Regional 

offices, states or local enforcement 

agencies. Thus, Executive Order 13132 

does not apply to this action. In the 

spirit of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between the EPA and 

state and local governments, the EPA 

specifically solicited comment on the 

proposed amendments from state and 

local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The final amendments will not 

have substantial direct effects on tribal 

governments, on the relationship 

between the federal government and 

Indian tribes, or on the distribution of 

power and responsibilities between the 

federal government and Indian tribes, as 

specified in Executive Order 13175. The 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37145 

final amendments impose no 

requirements on tribal governments. 

Thus, Executive Order 13175 does not 

apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying to those regulatory actions that 

concern health or safety risks, such that 

the analysis required under section 5– 

501 of the Order has the potential to 

influence the regulation. This action is 

not subject to Executive Order 13045 

because it is based solely on technology 

performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001) because it is not likely to have a 

significant adverse effect on the supply, 

distribution or use of energy. Further, 

we have concluded that the final 

amendments are not likely to have any 

adverse energy effects because they are 

cost neutral and may result in cost 

savings if the quarterly monitoring 

option is elected. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 12(d) (15 U.S.C. 272 note) directs 

the EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities, unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by VCS bodies. The NTTAA 

directs the EPA to provide Congress, 

through OMB, explanations when the 

agency decides not to use available and 

applicable VCS. 

This action does not involve any new 

technical standards. Therefore, the EPA 

did not consider the use of any 

additional VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994) establishes federal 

executive policy on environmental 

justice (EJ). Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make EJ part of their mission by 

identifying and addressing, as 

appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment. The final amendments 

do not relax the control measures on 

regulated sources, and, therefore, do not 

change the level of environmental 

protection. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801, et seq., as added by the 

Small Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. The EPA will 

submit a report containing this final rule 

and other required information to the 

United States Senate, the United States 

House of Representatives and the 

Comptroller General of the United 

States prior to publication of the final 

rule in the Federal Register. A major 

rule cannot take effect until 60 days 

after it is published in the Federal 

Register. This action is not a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). This 

final rule will be effective on June 20, 

2013. 

List of Subjects in 40 CFR Part 63 

Environmental protection, Air 

pollution control, Hazardous 

substances, Incorporation by reference, 

Reporting and recordkeeping 

requirements. 

Dated: June 12, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons stated in the 

preamble, the Environmental Protection 

Agency amends title 40, chapter I, of the 

Code of Federal Regulations as follows: 

PART 63—NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 1. The authority citation for part 63 

continues to read as follows: 

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

Subpart A—General Provisions 

■ 2. Section 63.14 is amended by 

revising paragraph (n)(1) to read 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—National Emission 

Standards for Hazardous Air Pollutants 

From Petroleum Refineries 

■ 3. Section 63.640 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (c)(8); 

■ c. Revising paragraph (h)(1) 

introductory text, adding paragraph 

(h)(1)(i) and revising paragraph 

(h)(1)(ii); and 

■ d. Removing reserved paragraph 

(h)(1)(iii) and paragraph (h)(1)(iv). 

The additions and 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. 

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37146 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

(ii) At new sources that commence 

construction or reconstruction after 

September 4, 2007, heat exchange 

systems shall be in compliance with the 

new source requirements in § 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., noncontact heat exchanger) and to transport 

and/or cool the water in a closed-loop 

recirculation system (cooling tower 

system) or a once-through system (e.g., 

river or pond water). For closed-loop 

recirculation systems, the heat exchange 

system consists of a cooling tower, all 

petroleum refinery process unit heat 

exchangers that are in organic HAP 

service, as defined in this subpart, 

serviced by that cooling tower, and all 

water lines to and from these petroleum 

refinery process unit heat exchangers. 

For once-through systems, the heat 

exchange system consists of all heat 

exchangers that are in organic HAP 

service, as defined in this subpart, 

servicing an individual petroleum 

refinery process unit and all water lines 

to and from these heat exchangers. 

Sample coolers or pump seal coolers are 

not considered heat exchangers for the 

purpose of this definition and are not 

part of the heat exchange system. 

Intentional direct contact with process 

fluids results in the formation of a 

wastewater. 

* * * * * 

In organic hazardous air pollutant 

service or in organic HAP service means 

that a piece of equipment either 

contains or contacts a fluid (liquid or 

gas) that is at least 5 percent by weight 

of total organic HAP as determined 

according to the provisions of 

§ 63.180(d) 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. 

* * * * * 

(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 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 closedloop recirculation heat exchange 

systems. For each closed loop 

recirculating heat exchange system, 

collect and analyze a sample from the 

location(s) described in either paragraph 

(c)(1)(i) or (c)(1)(ii) of this section. 

(i) Each cooling tower return line or 

any representative riser within the 

cooling tower prior to exposure to air for 

each heat exchange system. 

(ii) Selected heat exchanger exit 

line(s) so that each heat exchanger or 

group of heat exchangers within a heat 

exchange system is covered by the 

selected monitoring location(s). 

(2) Monitoring locations for oncethrough heat exchange systems. For 

each once-through heat exchange 

system, collect and analyze a sample 

from the location(s) described in 

paragraph (c)(2)(i) of this section. The 

owner or operator may also elect to 

collect and analyze an additional 

sample from the location(s) described in 

paragraph (c)(2)(ii) of this section. 

(i) Selected heat exchanger exit line(s) 

so that each heat exchanger or group of 

heat exchangers within a heat exchange 

system is covered by the selected 

monitoring location(s). The selected 

monitoring location may be at a point 

where discharges from multiple heat 

exchange systems are combined 

provided that the combined cooling 

water flow rate at the monitoring 

location does not exceed 40,000 gallons 

per minute. 

(ii) The inlet water feed line for a 

once-through heat exchange system 

prior to any heat exchanger. If multiple 

heat exchange systems use the same 

water feed (i.e., inlet water from the 

same primary water source), the owner 

or operator may monitor at one 

representative location and use the 

monitoring results for that sampling 

location for all heat exchange systems 

that use that same water feed. 

(3) Monitoring method. Determine the 

total strippable hydrocarbon 

concentration (in parts per million by 

volume (ppmv) as methane) at each 

monitoring location using the ‘‘Air 

Stripping Method (Modified El Paso 

Method) for Determination of Volatile 

Organic Compound Emissions from 

Water Sources’’ Revision Number One, 

dated January 2003, Sampling 

Procedures Manual, Appendix P: 

Cooling Tower Monitoring, prepared by 

Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated 

by reference—see § 63.14) using a flame 

ionization detector (FID) analyzer for 

on-site determination as described in 

Section 6.1 of the Modified El Paso 

Method. 

(4) Monitoring frequency and leak 

action level for existing sources. For a 

heat exchange system at an existing 

source, the owner or operator must 

comply with the monitoring frequency 

and leak action level as defined in 

paragraph (c)(4)(i) of this section or 

comply with the monitoring frequency 

and leak action level as defined in 

paragraph (c)(4)(ii) of this section. The 

owner or operator of an affected heat 

exchange system may choose to comply 

with paragraph (c)(4)(i) of this section 

for some heat exchange systems at the 

petroleum refinery and comply with 

paragraph (c)(4)(ii) of this section for 

other heat exchange systems. However, 

for each affected heat exchange system, 

the owner or operator of an affected heat 

exchange system must elect one 

monitoring alternative that will apply at 

all times. If the owner or operator 

intends to change the monitoring 

alternative that applies to a heat 

exchange system, the owner or operator 

must notify the Administrator 30 days 

in advance of such a change. All ‘‘leaks’’ 

identified prior to changing monitoring 

alternatives must be repaired. The 

monitoring frequencies specified in 

paragraphs (c)(4)(i) and (ii) of this 

section also apply to the inlet water feed 

line for a once-through heat exchange 

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Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 37147 

system, if monitoring of the inlet water 

feed is elected as provided in paragraph 

(c)(2)(ii) of this section. 

(i) Monitor monthly using a leak 

action level defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 6.2 ppmv. 

(ii) Monitor quarterly using a leak 

action level defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 3.1 ppmv unless 

repair is delayed as provided in 

paragraph (f) of this section. If a repair 

is delayed as provided in paragraph (f) 

of this section, monitor monthly. 

(5) Monitoring frequency and leak 

action level for new sources. For a heat 

exchange system at a new source, the 

owner or operator must monitor 

monthly using a leak action level 

defined as a total strippable 

hydrocarbon concentration (as methane) 

in the stripping gas of 3.1 ppmv. 

(6) Leak definition. A leak is defined 

as described in paragraph (c)(6)(i) or 

(c)(6)(ii) of this section, as applicable. 

(i) For once-through heat exchange 

systems for which the inlet water feed 

is monitored as described in paragraph 

(c)(2)(ii) of this section, a leak is 

detected if the difference in the 

measurement value of the sample taken 

from a location specified in paragraph 

(c)(2)(i) of this section and the 

measurement value of the 

corresponding sample taken from the 

location specified in paragraph (c)(2)(ii) 

of this section equals or exceeds the leak 

action level. 

(ii) For all other heat exchange 

systems, a leak is detected if a 

measurement value of the sample taken 

from a location specified in either 

paragraph (c)(1)(i), (c)(1)(ii), or (c)(2)(i) 

of this section equals or exceeds the leak 

action level. 

(d) If a leak is detected, the owner or 

operator must repair the leak to reduce 

the measured concentration to below 

the applicable action level as soon as 

practicable, but no later than 45 days 

after identifying the leak, except as 

specified in paragraphs (e) and (f) of this 

section. Repair includes re-monitoring 

at the monitoring location where the 

leak was identified according to the 

method specified in paragraph (c)(3) of 

this section to verify that the measured 

concentration is below the applicable 

action level. Actions that can be taken 

to achieve repair include but are not 

limited to: 

* * * * * 

(e) If the owner or operator detects a 

leak when monitoring a cooling tower 

return line under paragraph (c)(1)(i) of 

this section, the owner or operator may 

conduct additional monitoring of each 

heat exchanger or group of heat 

exchangers associated with the heat 

exchange system for which the leak was 

detected as provided under paragraph 

(c)(1)(ii) of this section. If no leaks are 

detected when monitoring according to 

the requirements of paragraph (c)(1)(ii) 

of this section, the heat exchange system 

is considered to meet the repair 

requirements through re-monitoring of 

the heat exchange system as provided in 

paragraph (d) of this section. 

(f) The owner or operator may delay 

the repair of a leaking heat exchanger 

when one of the conditions in paragraph 

(f)(1) or (f)(2) of this section is met and 

the leak is less than the delay of repair 

action level specified in paragraph (f)(3) 

of this section. The owner or operator 

must determine if a delay of repair is 

necessary as soon as practicable, but no 

later than 45 days after first identifying 

the leak. 

(1) If the repair is technically 

infeasible without a shutdown and the 

total strippable hydrocarbon 

concentration is initially and remains 

less than the delay of repair action level 

for all monthly monitoring periods 

during the delay of repair, the owner or 

operator may delay repair until the next 

scheduled shutdown of the heat 

exchange system. If, during subsequent 

monthly monitoring, the delay of repair 

action level is exceeded, the owner or 

operator must repair the leak within 30 

days of the monitoring event in which 

the leak was equal to or exceeded the 

delay of repair action level. 

(2) If the necessary equipment, parts, 

or personnel are not available and the 

total strippable hydrocarbon 

concentration is initially and remains 

less than the delay of repair action level 

for all monthly monitoring periods 

during the delay of repair, the owner or 

operator may delay the repair for a 

maximum of 120 calendar days. The 

owner or operator must demonstrate 

that the necessary equipment, parts, or 

personnel were not available. If, during 

subsequent monthly monitoring, the 

delay of repair action level is exceeded, 

the owner or operator must repair the 

leak within 30 days of the monitoring 

event in which the leak was equal to or 

exceeded the delay of repair action 

level. 

(3) The delay of repair action level is 

a total strippable hydrocarbon 

concentration (as methane) in the 

stripping gas of 62 ppmv. The delay of 

repair action level is assessed as 

described in paragraph (f)(3)(i) or 

(f)(3)(ii) of this section, as applicable. 

(i) For once-through heat exchange 

systems for which the inlet water feed 

is monitored as described in paragraph 

(c)(2)(ii) of this section, the delay of 

repair action level is exceeded if the 

difference in the measurement value of 

the sample taken from a location 

specified in paragraph (c)(2)(i) of this 

section and the measurement value of 

the corresponding sample taken from 

the location specified in paragraph 

(c)(2)(ii) of this section equals or 

exceeds the delay of repair action level. 

(ii) For all other heat exchange 

systems, the delay of repair action level 

is exceeded if a measurement value of 

the sample taken from a location 

specified in either paragraphs (c)(1)(i), 

(c)(1)(ii), or (c)(2)(i) of this section 

equals or exceeds the delay of repair 

action level. 

(g) To delay the repair under 

paragraph (f) of this section, the owner 

or operator must record the information 

in paragraphs (g)(1) through (4) of this 

section. 

(4) An estimate of the potential 

strippable hydrocarbon emissions from 

the leaking heat exchange system or 

heat exchanger for each required delay 

of repair monitoring interval following 

the procedures in paragraphs (g)(4)(i) 

through (iv) of this section. 

(i) Determine the leak concentration 

as specified in paragraph (c) of this 

section and convert the stripping gas 

leak concentration (in ppmv as 

methane) to an equivalent liquid 

concentration, in parts per million by 

weight (ppmw), using equation 7–1 

from ‘‘Air Stripping Method (Modified 

El Paso Method) for Determination of 

Volatile Organic Compound Emissions 

from Water Sources’’ Revision Number 

One, dated January 2003, Sampling 

Procedures Manual, Appendix P: 

Cooling Tower Monitoring, prepared by 

Texas Commission on Environmental 

Quality, January 31, 2003 (incorporated 

by reference—see § 63.14) and the 

molecular weight of 16 grams per mole 

(g/mol) for methane. 

(ii) Determine the mass flow rate of 

the cooling water at the monitoring 

location where the leak was detected. If 

the monitoring location is an individual 

cooling tower riser, determine the total 

cooling water mass flow rate to the 

cooling tower. Cooling water mass flow 

rates may be determined using direct 

measurement, pump curves, heat 

balance calculations, or other 

engineering methods. Volumetric flow 

measurements may be used and 

converted to mass flow rates using the 

density of water at the specific 

monitoring location temperature or 

using the default density of water at 25 

degrees Celsius, which is 997 kilograms 

per cubic meter or 8.32 pounds per 

gallon. 

(iii) For delay of repair monitoring 

intervals prior to repair of the leak, 

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37148 Federal Register / Vol. 78, No. 119 / Thursday, June 20, 2013 / Rules and Regulations 

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 remonitoring event used to verify the leak 

was repaired. The duration of the final 

delay of repair monitoring interval is the 

time period starting at midnight of the 

day of the last monitoring event prior to 

re-monitoring to verify the leak was 

repaired and ending at the time of the 

re-monitoring event that verified that 

the leak was repaired. 

■ 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: 

(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 re-monitoring to verify repair, 

and the re-monitoring date (i.e., the 

effective date of repair); and 

(v) For each delayed repair, 

identification of the monitoring location 

associated with the leak for which 

repair is delayed, the date when the 

delay of repair began, the date the repair 

is expected to be completed (if the leak 

is not repaired during the reporting 

period), the total strippable hydrocarbon 

concentration and date of each 

monitoring event conducted on the 

delayed repair during the reporting 

period, and an estimate of the potential 

strippable hydrocarbon emissions over 

the reporting period associated with the 

delayed repair. 

(h) * * * 

(7) The owner or operator of a heat 

exchange system at an existing source 

must notify the Administrator at least 30 

calendar days prior to changing from 

one of the monitoring options specified 

in § 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 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. 

(v) If a repair is delayed, the reason 

for the delay, the schedule for 

completing the repair, the heat exchange 

exit line flow or cooling tower return 

line average flow rate at the monitoring 

location (in gallons/minute), and the 

estimate of potential strippable 

hydrocarbon emissions for each 

required monitoring interval during the 

delay of repair. 

* * * * * 

[FR Doc. 2013–14624 Filed 6–19–13; 8:45 am] 

BILLING CODE 6560–50–P 

DEPARTMENT OF COMMERCE 

National Oceanic and Atmospheric 

Administration 

50 CFR Part 622 

[Docket No. 1206013412–2517–02] 

RIN 0648–XC702 

Fisheries of the Caribbean, Gulf of 

Mexico, and South Atlantic; 2013 

Commercial Accountability Measure 

and Closure for Gulf of Mexico Greater 

Amberjack 

AGENCY: National Marine Fisheries 

Service (NMFS), National Oceanic and 

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