6/18/2020 - Delaware

REVIEW MEMORANDUM 7 DE Admin. Code 1130 (TITLE V) OPERATING PERMIT

City of Dover McKee Run Generating Station

880 Buttner Place

Dover, Delaware 19904 DRAFT/PROPOSED Permit: AQM-001/00002 (Renewal 4)

TO: Angela D. Marconi, P.E., BCEE

THROUGH: Joanna L. French, P.E.

FROM: Jordan G. Matthews, P.E.

DATE: June 17, 2020

BACKGROUND On April 21, 2017 the Department received the permit renewal application for the Title V permit (Permit:

AQM-001/00002) at the City of Dover McKee Run Generating Station (MRGS). A revised permit

application was later received by the Department on August 16, 2018. Both applications were prepared by NAES and submitted by the City of Dover. The MRGS is a power generation plant owned by the City of

Dover and operated by NAES. According to the application, the facility is operated as a “peaker power plant”, which means it is primarily called upon to operate by the regional electrical grid system operator –

Pennsylvania, New Jersey, Maryland (PJM) – during peak demand days when the other available sources of generation are inadequate.

The existing permit for the facility allowed for the operation of three (3) boilers with associated steam turbines for the generation of power, two (2) hot water boilers, two (2) cold solvent cleaners, and one (1)

fuel storage tank. An emergency fire pump engine, which was not given an emission unit identification number, was also included in the existing permit under the “facility wide” section. Table 1 summarizes the

emission units which were permitted by Permit: AQM-001/00002 (Renewal 3):

Emission Units Emission Unit Description

Emission Units 1 and 2 Two (2) 225 MMBTU/hr Babcock & Wilcox Boilers; Fired on No. 2 Fuel Oil

and Natural Gas

Emission Unit 3 1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on No. 2 Fuel

Oil and Natural Gas

Emission Units 4 and 5 Two (2) 13.39 MMBTU/hr Boiler Engineering and Supply Company Hot Water Boilers; Fired on Natural Gas

Emission Units 6 and 7 Two (2) Cold Solvent Cleaners

Emission Unit 8 2,704,800 Gallon No. 2 Fuel Oil Storage Tank

Table 1: Emission Units Permitted by Permit: AQM-001/00002 (Renewal 3)

On June 22, 2017 I visited the MRGS to inspect the two (2) 225 MMBTU/hr boilers which were being

retired. I observed that the natural gas and No. 2 fuel oil supply lines had been capped off to prevent future operation of the emission units. Consequently, all reference to and requirements associated with

the 225 MMBTU/hr boilers have been removed from this permit. Table 2 summarizes the units that are

covered by this permit renewal.

6/18/2020

Carla.Godwin

New Stamp

Review MEMORANDUM DRAFT/PROPOSED Permit: AQM-001/00002 (Renewal 4)

City of Dover McKee Run Generating Station June 17, 2020

Page 2


Emission Unit 3 1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on No. 2 Fuel

Oil and Natural Gas




Table 2: Emissions Units Permitted by Permit: AQM-001/00002 (Renewal 4)

Despite the removal of the two (2) 225 MMBTU/hr boilers from the permit, the facility’s operations still have the potential to emit (PTE) above the major source threshold for nitrogen oxides (NOX), carbon

monoxide (CO), particulate matter (PM10), and volatile organic compounds (VOCs). Table 3 summarizes the PTE at the MRGS.

Pollutant

Emissions by Source (TPY)

Total

(TPY)

Major

Source Threshold

(TPY) for Kent

County

Major Source

for Pollutant?

Emission Unit 3

Emission Unit 4

Emission Unit 5

SOX 20.915 0.034 0.034 20.983 100 NO

NOX 1,586.699 5.586 5.586 1,597.871 25 YES

CO 413.472 4.692 4.692 422.856 100 YES

PM10 302.351 0.425 0.425 303.201 100 YES

VOCs 27.073 0.307 0.307 27.687 25 YES

Table 3: MRGS Facility-wide PTE

Emissions from the two (2) cold solvent cleaners and 2,704,880 gallon No. 2 fuel oil storage tank were not

included in this estimate. These sources would be additional sources of VOCs, for which the facility is already considered major. Emissions from the emergency fire pump engine also were not considered in

this estimation. As an emission source of the typical byproducts of combustion, the inclusion of the emergency fire pump engine would have no impact on the facility’s status as a Title V source for any of the

pollutants summarized in Table 3.

The MRGS is current with their fees. The status of their fees was checked on July 22, 2019. Figure 1 is a

screenshot from the Delaware Environmental Navigator (DEN) from this date which shows that the MRGS has made the required payments for each year dating back to 2013.

Figure 1: Screenshot from DEN showing payment status for MRGS



Page 3

CORRESPONDENCE CHRONOLOGY Table 4 summarizes the correspondences that occurred as part of the renewal process.

Date Correspondence Subject

4/21/17 Permit Renewal Application Permit Renewal Application for Renewal 4

8/16/18 Revised Permit Renewal

Application Revised Permit Renewal Application for Renewal 4

4/24/20 Email Requested submission of Acid Rain Permit Application

4/28/20 Email Received Acid Rain Permit Application from NAES on behalf

of City of Dover

Table 4: Permit Renewal Correspondence Summary

EMISSION POINT AND EMISSION UNIT IDENTIFICATION

The MRGS owns and operates six (6) emission units which have dedicated sections in this permit renewal. Table 5 summarizes the emission units subject to the Title V operating program:

Emission

Unit ID Emission Unit Description

Emission

Unit 3 1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on No. 2

Fuel Oil and Natural Gas

Emission

Unit 8 2,704,800 Gallon No. 2 Fuel Oil Storage Tank

Table 5: Emission Units Subject to 7 DE Admin. Code 1130 Operating Permit Program

Emission Unit 8 would be exempt from permitting requirements by itself, under Item 21 of Appendix A to 7

DE Admin. Code 1102; however, it does not meet the definition of an “Insignificant Activity” as specified by 7 DE Admin. Code 1130.

INSIGNIFICANT ACTIVITIES Table 6 summarizes the equipment identified as insignificant activities under 7 DE Admin. Code 1130.

These emission units are regulated by the Department due to the facility’s Title V status.

Emission

Unit ID Description Basis

Emission

Unit 4

13.39 MMBTU/hr Natural Gas-fired

Boiler Engineering

and Supply Company Hot Water Boiler

Paragraph 2.1 of Appendix A to 7 DE Admin. Code 1130 states

that “fuel burning equipment which uses any fuel and has a rated heat input of less than 15 million BTU per hour” is considered an

Insignificant Activity. Emission

Unit 5

13.39 MMBTU/hr Natural Gas-fired

Boiler Engineering

and Supply Company Hot Water Boiler



Page 4

Emission

Unit ID Description Basis

Emission

Unit 6

Graymills Clean-O-Matic Cold Solvent

Cleaner

Paragraph 19 of Appendix A to 7 DE Admin. Code 1130 states

that “any activity related to routine maintenance and repair of a facility where emissions would not be associated with a primary

production process of the facility” is considered an insignificant

activity. Under paragraph A it states that “such activities may include...cleaning...solvent use...degreasing...washing”. These

are the types of activities that are associated with the cold

solvent cleaners.

Emission

Unit 7

Graymills Clean-O-

Matic Cold Solvent Cleaner

Table 6: Equipment Identified as Insignificant Activities

As mentioned before, there is also an emergency fire pump engine located at the MRGS. Historically, this

emission source has not been given its own designation, but is permitted under the “Facility Wide” section

of the permit. Regardless, this engine would also be considered an “insignificant activity” under Section 2.2 of Appendix A to 7 DE Admin. Code 1130 because it is an internal combustion engine which drives a

water pump during emergency operations.

EXISTING 7 DE Admin. Code 1102 PERMITS

Table 7 summarizes the existing 7 DE Admin. Code 1102 permits assigned to the equipment at the MRGS.

Permit Number and Date Permitted Equipment

APC-1981/1121-OPERATION

(Amendment 4)

1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on No. 2

Fuel Oil and Natural Gas

APC-1981/1122-OPERATION Two (2) 13.39 MMBTU/hr Boiler Engineering and Supply Company Hot

Water Boilers; Fired on Natural Gas APC-1981/1123-OPERATION

Table 7: Existing 7 DE Admin. Code 1102 Permits

The permits shown in Table 7 are existing 7 DE Admin. Code 1102 permits for the MRGS. However, as

part of this renewal, I drafted amendments to the 7 DE Admin. Code 1102 permits shown in Table 7.

This includes Permits: APC-1981/1121-OPERATION (Amendment 5), APC-1981/1122-OPERATION (Amendment 1), APC-1981/1123-OPERATION (Amendment 1), and. The

requirements of these permits were amended with the intention of ensuring agreement with the renewed Title V permit.

REGULATORY REVIEW/TECHNICAL REVIEW/COMPLIANCE METHODOLOGY A regulatory review was conducted for each emission unit at the MRGS. The following sections focus on

the existing sections of the permit for the six (6) emission units at the MRGS, and on the changes required within each.

Emission Unit 3 (1,180 MMBTU/hr Riley Stoker Boiler) The changes made in this permit related to Emission Unit 3 are discussed in detail in the memo associated

with the amendment to the 7 DE Admin. Code 1102 permit for Emission Unit 3. Rather than rehash these details again, the following paragraphs summarize the changes made – starting with the section of

the permit focusing on particulate matter (PM) emissions from Emission Unit 3.

Particulate Matter (PM)

The first section of the portion of the permit focusing on Emission Unit 3 details the requirements related to PM. In this renewal, the emission standard for PM remains the same, but the language has changed



Page 5

slightly to clarify the type of PM (filterable) that is being regulated.

In terms of emission limitations, the renewal has a couple of distinct changes from the existing permit. For one, the particulate emissions are no longer limited as an aggregate from Emission Units 1-3. Emission

Units 1 & 2 were retired from service in June of 2017 and have been removed from the permit. This same change applies to the emission limitations for all pollutants for which Emission Unit 3 is regulated since

they were previously based on combined emissions from emissions from all three (3) of the boilers.

With that being said, the numerical value for the twelve (12) month emission limitation for PM is increasing

from 51.75 to 54.85 tons due to a change in the emission factor used to calculate the particulate matter emitted from Emission Unit 3. The new emission factors consider both condensable and filterable

particulate matter emissions, whereas the emission factor used in the existing permit only considered

filterable particulate emissions. This increase is only numerical. There has been no relaxation of limitations or standards that would allow for an actual increase in emissions.

Moving on, the language within the compliance methodology section was tweaked to require subsequent

stack testing for PM for the life of the Emission Unit, and to provide specific guidance on the Department’s expectation in terms of the calculation of PM10 emissions. The monitoring section language was also

modified to remove reference to the ash reinjection system, achievement of pilot ignition, ash level in the

multicyclone hopper, and the pressure differentials across the separator/collector. These requirements were acknowledged as no longer being necessary in amendments made to the Title V and 7 DE Admin.

Code 1102 permits between 2009 and 2010, but inadvertently remained in the Title V permit. The testing and recordkeeping sections of the permit were modified to correspond with the above changes.

Sulfur Dioxide (SO2) For the section of the permit devoted to Emission Unit 3 SO2 emissions, the proposed twelve (12) month

emission limitation is decreasing substantially. This is partly because the limitation no longer includes cumulative emissions from Emission Units 1-3, but more importantly, because it considers the drop in No. 2

fuel oil sulfur content. The emission limitation is proposed to decrease from 400 tons to 3.88 tons on a

rolling twelve (12) month basis. As a result, the MRGS is no longer considered a Title V source for emissions of SO2.

Going along with the emission limitation decrease, the standard on the sulfur content of No. 2 fuel oil has

been updated to the 15 ppm standard established by 7 DE Admin. Code 1108. Recent inspections have verified that the MRGS has been receiving fuel oil with a sulfur content of 15 ppm, but the permit had not

been amended to explicitly require it.

The previous restriction that No. 2 fuel oil could only be combusted as a backup/emergency fuel has also

been removed. I believe this restriction was mistakenly included as a way to avoid subjection to Subpart JJJJJJ (6J) to 40 CFR Part 63, with which Emission Unit 3 is already exempt since it does not meet the

definition of an industrial, commercial, or institutional boiler as the terms are defined in §63.11237.

Emission Unit 3 combusts natural gas when it is available and is already restricted in the volume of No. 2 fuel oil which can be combusted under Subpart UUUUU (5U) to 40 CFR Part 63.

The subsection of the permit focusing on compliance methods was also amended in this renewal in order

to clarify the Department’s compliance expectations. The testing and recordkeeping sections were also amended to correspond to the previous emission limitations, operating limitations, and associated methods

of demonstrating compliance.



Page 6

Visible Emissions The structure of this section was modified in this renewal, but the requirements are unchanged. For

example, the same opacity standards apply as does the requirement to operate a continuous opacity monitoring system (COMS) at all times and pursuant to the applicable requirements of Appendix B of 40

CFR Part 60. Just as with the preceding sections, the proposed language in the compliance method section is more specific about the steps and information required to determine compliance status than was the

previous permit. The monitoring and recordkeeping subsections were also amended to correspond to the

associated limitations.

Nitrogen Oxide Emissions Minor changes were made to the section of the permit focusing on Emission Unit 3 NOX emissions. First of

all, the calendar-day 0.307 lbs NOX/MMBTU standard was moved from the emission limitation section to

the emission standard section. The existing limitations which restrict NOX emissions to 244 tons per rolling twelve (12) month period and 2.93 tons per calendar-day during the ozone control period remain

unchanged.

There are a few proposed changes to the operating limitations section of the permit. The first couple conditions, regarding the continuous operation of NOX control equipment (low NOX burner, low excess air,

& overfire air system) and a NOX CEMS, will remain in this section, but with a slight change in language. In

response to the Regional Haze Rule initiative currently being spearheaded by Renae Held, the requirement to not only operate, but also maintain this equipment in accordance with manufacturer recommendations

has been included. The remaining requirements from this section have been rearranged. For example:

The requirement that the GCV of fuel oil samples be available within thirty (30) calendar-days was moved to the section focusing on SO2 emissions since its inclusion was a more natural fit there

with the other fuel sampling and testing requirements focusing on fuel sulfur content.

The requirement focusing on the calibration of in-line fuel flow meters was also moved to the

section of the permit focusing on SO2 emissions as a method of demonstrating compliance with

the operational limitation to combust only natural gas or No. 2 fuel oil in Emission Unit 3.

The existing condition focusing on the replacement of the 0.307 lb NOX/MMBTU standard was

removed from the permit for several reasons: o The permit language was unclear as to how or when the replacement of this standard

should occur. o The data collected by the Department during annual inspections and records reviews has

not shown that NOX emissions are well below the current standard. o Additional NOX control technology would likely need to be installed and operated in order

for Emission Unit 3 to meet a reduced standard. o There are no other applicable regulatory requirements which would provide a basis for

further reduction on the existing standard. o Emission Unit 3 at the MRGS is currently scheduled for decommissioning in June of 2021,

and any further reduction of the NOX standard would not likely provide long-term benefit to the environment.

The requirement regarding the need for a corrective action plan if calendar-day NOX emissions

from Emission Unit 3 exceed the 2.93-ton limit during the ozone control period was moved to the compliance methodology subsection as a corrective action in the case that compliance with this

limit is not achieved. As was the case for the preceding sections, the compliance methodology, monitoring, and recordkeeping sections were amended to correspond to the applicable emission and operational standards and limitations.

The only notable difference in these sections, is that the threshold related to the requirement to report



Page 7

excess emissions has been lowered from 0.50 lb NOX/MMBTU on an average, rolling twenty-four hour basis to 0.307 lb NOX/MMBTU over the same time period. It was not clear to me why the reporting threshold

was set at 0.50 lbs/MMBTU, but I speculate that the higher value may have been a prior emission standard, and the language was not modified to reflect the lower standard.

Other Criteria Pollutants

The fifth section of the permit focuses on “Other Criteria Pollutants” such as carbon monoxide (CO) and

volatile organic compounds (VOCs). In this section of the permit, the twelve (12) month emission limitation for CO is remaining the same, but the emission limitation for VOCs is decreasing from 23.15 tons

to a mere 6.66 tons over the same twelve (12) month period. Aside from that decrease, the only notable difference in this section is that the compliance method subsection includes specific instruction on the

calculation of CO and VOC emissions from Emission Unit 3.

Allowable Operating Scenarios

The final section of the permit under Emission Unit 3 is titled “Allowable Operating Scenarios” since it details the two (2) different scenarios under which Emission Unit 3 may operate. This section is new to the

permit.

The first operating scenario is allowable under the existing permit – operation as a “natural gas-fired

electric utility steam generating unit”. Operation under this scenario allows Emission Unit 3 to remain exempt from the requirements of Subpart 5U to 40 CFR Part 63 so long as the heat input contributed by

the combustion of No. 2 fuel oil does not exceed 10.0% of the average annual heat input contributed by the combustion of all fuels over the previous three (3) calendar years or 15.0% of the annual heat input

contributed by the combustion of all fuels over any single calendar year.

The City of Dover requested, and I am proposing approval for, the flexibility to operate under the “limited-

use liquid oil-fired subcategory” of Subpart 5U to 40 CFR Part 63 should this become necessary. This flexibility will allow Emission Unit 3 to combust No. 2 fuel oil during the winter months when natural gas

may not be available without needing to unnecessarily combust additional natural gas during the summer

months to meet the heat input ratio required to remain exempt from Subpart 5U. With that being said, the permit has included the requirements and conditions that would apply if the MRGS decides to operate

Emission Unit 3 as a unit subject to the Subpart 5U requirements.

The compliance methodology, monitoring, and recordkeeping sections were modified to correspond to the requirements for each of the operating scenarios. Further information on the requirements of this section,

and all preceding sections, can be found in the memorandum corresponding to Permit: APC-

1981/1121-OPERATION (Amendment 5).

Emission Units 4 & 5 (Two (2) 13.39 MMBTU/hr Natural Gas-Fired Hot Water Boilers) In the existing Title V permit, there is only one section focusing on the operation of the two (2) hot water

boilers at the MRGS. In this renewal, I am proposing three (3) separate sections – the first of which being

a section focused on the emission of criteria pollutants.

Criteria Pollutants This section of the permit replaces the section of the existing permit, which focused on PM emissions, but

still includes those relevant requirements. Some notable changes made in this section:

The removal of the emission standard from 7 DE Admin. Code 1104; and

The addition of emission limitations for each of the primary pollutants emitted from fuel combustion – SO2, NOX, CO, PM10, and VOCs.

While the emission standard from 7 DE Admin. Code 1104 (0.3 lb PMFilt/MMBTU) applies to these boilers,



Page 8

it seemed unnecessary to include it in the permit because the proposed PM10 emission limitation, which includes emissions of filterable and condensable (PM) emissions (7 DE Admin. Code 1104 only focuses on

filterable PM emissions) is based on an emission factor of 7.6 lbs PM10/MMSCF (which equates to roughly 0.007 lbs PM10/MMBTU, assuming a heating value of 1,050 MMBTU/MMSCF for natural gas). Furthermore,

there are no regulatory or permit requirements which would necessitate the testing or monitoring of exhaust gas from the hot water boilers to confirm that the boilers are meeting the standard.

The only new items for this section are the new emission limitations, and the corresponding requirement to calculate these emissions based on AP-42 emission factors. The emissions from the hot water boilers are

already calculated for the purposes of the annual emission inventory. Requiring this calculation as part of the Title V permit should not represent an additional burden.

Opacity This is another new section related to Emission Units 4 & 5. While the opacity standard was previously in

place for the entire facility, there were no direct observation requirements for these boilers. I am proposing the requirement to conduct quarterly qualitative visible emission observations. To demonstrate

compliance with this requirement, the results of the observations shall be recorded.

The reasoning for this addition is fairly straight-forward. Inspections of the MRGS are generally conducted

during the summer months when Emission Unit 3 is expected to operate. Unfortunately, the hot water boilers do not operate during this time of year. Since the Department is generally not on-site at the time

of year to conduct observations, the quarterly opacity observation simply requires an onlooker to observe and confirm that the boilers are not producing opacity. Reference Method 9 certification is not necessary.

If opacity is observed, the permit instructs the observer to initiate and record corrective action taken in

response to the observed opacity.

General Equipment Operation/Maintenance The final section related to Emission Units 4 & 5 covers the topic of general operation and maintenance .

While this section is new, the requirements have always applied even if they’ve been located elsewhere in

the permit. Corresponding compliance methodology, monitoring, and recordkeeping requirements were also included in this section.

Emission Units 6 & 7 (Two (2) Cold Solvent Cleaners)

Like the existing permit, the renewal permit is proposed to have only a single section related to the operation of the cold solvent cleaners on site. There are no noteworthy modifications to this section of the

permit.

Emission Unit 8 (2,704,800 Gallon No. 2 Fuel Oil Storage Tank)

Like the existing permit, the renewal permit is proposed to have only a single section related to the operation of the No. 2 fuel oil storage tank at the MRGS. There are no noteworthy modifications to this

section of the permit.

Facility Wide

Like the existing permit, the renewal permit is proposed to have six (6) sections under the “Facility Wide” heading – the first of which being a section focused on the disposal, handling, and storage of VOCs.

Disposal, Handling, and Storage of Volatile Organic Compounds (VOCs)

This section of the permit focuses on requirements coming primarily from Section 8 of 7 DE Admin. Code

1124. The contents of this section have not been changed, although some of the permit language has been modified with the intent of providing greater direction.



Page 9

Visible Emissions

This section of the permit focuses on the prevention of visible emissions from permitted equipment at the MRGS. While visible emissions from Emission Units 3, 4, & 5 are regulated under their respective permit

sections, this section provides instruction for conducting informal observations of other equipment, such as the emergency fire pump engine, to ensure visible emissions do not occur elsewhere. There are no

requirements to document the informal observations, but there are requirements to correct and document

any instances where standard-exceeding opacity is observed.

Operations/Maintenance This section of the permit focuses on the operation and maintenance of permitted equipment at the MRGS,

especially as it relates to maintenance or operation that could have an impact on the generation and

release of pollutants to the air. The contents of this section have not been substantially changed. Similar to preceding sections, the changes made have been to include more specific direction on the Department’s

expectations as well as recordkeeping requirements.

Architectural and Industrial Maintenance Coatings This section of the permit focuses on the application of architectural and industrial maintenance coatings at

the MRGS and originate from 7 DE Admin. Code 1141. The existing permit contains requirements from

this regulation which were last updated in November of 2006. Since then, this regulation was amended, and this renewal now contains the updated regulatory language from a December 2016 amendment. With

that being said, the requirements are not significantly different.

State Enforceable Only (Odors)

This section of the permit focuses on preventing the generation of odorous air pollutants from permitted equipment or other operations at the MRGS. Odorous conditions are not anticipated from site operations,

but in the case that they are detected, the owner or operator is responsible for taking corrective action in a timely manner and documenting the actions taken. There are no new requirements in this section.

Emergency Spark Ignition (SI) Fire Pump Engine (40 CFR Part 63 Subpart ZZZZ (4Z)) The final section of the “Facility Wide” portion of the permit focuses solely on the emergency fire pump

engine located at the MRGS. While the language and detailed compliance instructions were amended, the actual requirements have not changed.

7 DE Admin. Code 1136 – Acid Rain Program

In addition to the previously mentioned permit sections, Emission Unit 3 is also subject to the applicable

requirements of the Acid Rain Program which is regulated under Parts 72 through 78 of Title 40 of the Code of Federal Regulations (CFR) and incorporated by reference in 7 DE Admin. Code 1136. A permit

application for an Acid Rain Permit for Emission Unit 3 was received by the Department electronically on April 28, 2020. A final section of the permit references the Acid Rain Permit for Emission Unit 3 (Permit:

AQM-001/00002-IV (Renewal 4).

Permit Shield

In the permit application received in April 2017, the City of Dover provided an update of the regulatory requirements for which they were requesting a Permit Shield. Table 8 summarizes the regulatory

requirements for which a permit shield was granted.

Review MEMORANDUM Draft/Proposed Permit: AQM-001/00002 (Renewal 4)

City of Dover McKee Run Generating Station April 30, 2020

Page 10

Emission Unit Applicable Requirement

Emission Unit 3

Sections 2.1 and 2.2 of 7 DE Admin.

Code 1104

Sections 2.2, 2.3, and 2.4 of 7 DE

Admin. Code 1108

Section 3.5 of 7 DE Admin. Code 1112


Emission Units 4 & 5

Sections 2.1 and 2.2 of 7 DE Admin.

Code 1104

Sections 2.2, 2.3, & 2.4 of 7 DE Admin.

Code 1108

Emission Units 6 & 7 Sections 5 and 33 of 7 DE Admin. Code

1124

Emission Unit 8 Section 49 of 7 DE Admin. Code 1124

Facility Wide

Sections 1 through 11 of 7 DE Admin.

Code 1103

Section 2 of 7 DE Admin. Code 1114

Sections 7 and 8 of 7 DE Admin. Code

1124


Table 8: Regulatory Requirements for which a Permit Shield was Granted

Aside from the regulatory requirements summarized in Table 8, the City of Dover’s permit application also

requested a permit shield from the requirements of 40 CFR Part 72 through 75. Upon discussing this request with my manager, we agreed that this request was too broad for approval and have decided not

to grant a permit shield for the federal parts.

RECOMMENDATIONS

The draft/proposed permit and application will be advertised, beginning on Sunday, June 21, 2020, for a thirty (30) day public notice period. I recommend that the draft/proposed permit and associated

documents be sent to EPA’s Region III representatives by email to begin the review period for this Title V permit renewal. I also recommend that the draft/proposed permit be sent to the City of Dover so that

they may concurrently review the permit contents and provide any comments they feel are necessary. In

addition, I recommend that the Affected States be notified by email and provided with Sections A and B, which explain the draft/proposed permit.

The public comment period ends on July 21, 2020. The EPA’s 45-day review period will run concurrently

with the public comment period, and will end on August 5, 2020.

ADM:JLF:JGM:tmm F:\EngAndCompliance\JGM\2020\JGM20037.doc pc: Dover Title V File

TITLE V PERMIT REVIEW

PERMIT APPLICATION CHECKLIST

STATE:

SOURCE NAME:

AFS PLANT ID:

SOURCE TYPE: PERMIT #:

SIC #:

SOURCE LOCATION (COUNTY):

I. Is this a general permit? If yes, which one? (Go to Part III).................................YES/NO

If no, go to Part II.

II. PROGRAM IMPLEMENTATION

Does this permit contain “streamlined limits” (per White Paper #2)...................................................YES/NO

Does this permit contain requirements/provisions for:

1. Periodic Monitoring................................................................................................YES/NO

2. NESHAP/MACT (if so, list subparts).....................................................................YES/NO

3. Case-by-Case MACT.............................................................................................YES/NO

4. NSPS (if so, list subparts)............................................................................YES/NO – list

5. PSD/NSR............................................................................................YES/NO (PSD/NSR)

6. Acid Rain Phase II Permit.......................................................................................YES/NO

7. Potential-to-Emit Limits..........................................................................................YES/NO

8. Consent Order Agreement......................................................................................YES/NO

9. NOX RACT.............................................................................................................YES/NO

10. VOC RACT............................................................................................................YES/NO

11. Does permit application contain confidential information?....................................YES/NO

III. COMPLIANCE STATUS

Is the Source subject to a compliance schedule?...................................................................YES/NO

IV. EPA REVIEW

1. Do you want EPA to review all or part of this permit?...........................................YES/NO

2. Are there other issues you would like to call to EPA’s attention?..........................YES/NO

STATE CONTACT: DATE: Proposed Issue Date

PHONE:

(for EPA use only) dated entered init action ver

13sep96cklst.app

ENGINEERING &

COMPLIANCE

DEPARTMENT OF NATURAL RESOURCES AND

ENVIRONMENTAL CONTROL

DIVISION OF AIR QUALITY

STATE STREET COMMONS

100 W. WATER STREET, SUITE 6A

DOVER, DELAWARE 19904

PHONE

(302) 739-9402

June 18, 2020

City of Dover 880 Buttner Place

Dover, DE 19904

ATTENTION: Donna Mitchell

City of Dover, City Manager

SUBJECT: Permit: AQM-001/00002 (Renewal 4) “Draft/Proposed” 7 DE Admin. Code 1130 Permit Renewal

Dear Ms. Mitchell:

The Department has completed processing the City of Dover McKee Run Generating Station’s AQM-1001 series permit renewal applications that were submitted on April 21, 2017 and August 14, 2018, to the

Department pursuant to 7 DE Admin. Code 1130. The Department has reviewed the submitted information and has prepared the attached “Draft/Proposed” permit renewal satisfying the requirements of

7 DE Admin. Code 1130.

The attached “Draft/Proposed” permit renewal specifies the terms and conditions, Conditions 2 through 6,

under which the City of Dover McKee Run Generating Station will be permitted to operate the emission units listed in Condition 1. In addition to the emission units listed in Condition 1, the City of Dover McKee

Run Generating Station will be permitted to operate all activities with air emissions that are not listed in

Condition 1 and that are designated as insignificant activities under 7 DE Admin. Code 1130 or designated as trivial activities under Appendix “A” of the Department’s summary of the July 10, 1995, EPA

“White Paper for Streamlined Development of Part 70 Permit Applications,” notwithstanding 7 DE Admin. Code 1102.

The attached “Draft/Proposed” permit renewal covers only the operating permit requirements of 7 DE

Admin. Code 1102 and 1130. The attached “Draft/Proposed” permit renewal does not satisfy future

construction permit obligations. Prior to initiating any construction or modification activity the City of Dover McKee Run Generating Station must evaluate the applicability of, and, if required, secure necessary

construction permit(s) pursuant to 7 DE Admin. Code 1102 or 1125, and/or initiate necessary permit revision procedures pursuant to 7 DE Admin. Code 1102 and 1130.

The Department will public notice the “Draft/Proposed” permit renewal as required by 7 DE Admin. Code 1130, Section 7.10 in the Sunday News Journal and the Delaware State News on Sunday, June 21, 2020.

The public comment period will be no less than thirty (30) days in accordance with 7 DE Admin. Code 1130, Section 7.10.2. The public comment period ends July 21, 2020. Any comments should be brought

to the Department’s attention on or before July 21, 2020 and mailed to the following address:

“Draft/Proposed” Permit: AQM-001/00002 (Renewal 4) City of Dover McKee Run Generating Station May 15, 2020 Page 2

State of Delaware - DNREC Division of Air Quality

State Street Commons 100 W. Water Street, Suite 6A

Dover, DE 19904

ATTN: David Fees

The Department requests that you mail the original and one (1) copy if you submit comments. The “Draft/Proposed” permit is being submitted to EPA for concurrent processing. Please note that the EPA can comment during the 30 day public notice period and can approve or deny the permit during the entire 45 day EPA review period. The EPA review period ends on August 5, 2020. If the Department receives significant comments on the “Draft/Proposed” renewal permit, comments will be evaluated, responses will be prepared, and the renewal permit will be revised as necessary. The permit will then be submitted to you and the EPA as “Proposed” as a standard consecutive forty-five (45) day review period. Any questions concerning the attached “Draft/Proposed” permit renewal may be directed to Jordan Matthews or me at (302) 739-9402.

Sincerely,

Joanna L. French, P.E.

Managing Engineer

Engineering & Compliance Branch JLF:JGM:tmm F:\EngAndCompliance\JGM\2020\JGM20041.doc pc: Dover File

Joanna French Jordan Matthews

State of Delaware Department of Natural Resources and Environmental Control

Division of Air Quality State Street Commons

100 W. Water Street, Suite 6A Dover, DE 19904

7 DE Admin. Code 1130 (Title V) Operating Permit Facility I.D. Number: 1000100002

Draft/Proposed Permit Number: AQM-001/00002 (Renewal 4)

Effective Date: <insert date> Expiration Date: <insert date> Renewal Application Due Date: <insert date>

Pursuant to 7 Del. C., Ch 60, Section 6003, 7 DE Admin. Code 1102 Section 2.0, and 7 DE Admin.

Code 1130 Section 7.2, approval by the Department of Natural Resources and Environmental Control

(“Department”) is hereby granted to operate the emission units listed in Condition 1 of this permit subject

to the terms and conditions of this permit.

This approval is granted to:

Permittee/Owner

(hereafter referred to as “Company/Owner”)

Operator

(hereafter referred to as “Operator”)

City of Dover P.O. Box 475

Dover, Delaware 19903-0475 Responsible Official: Donna Mitchell

Title: City Manager

NAES 880 Buttner Place

Dover, Delaware 19904 Designated Rep: Stacy Johnson

Title: Plant Manager

Plant Site Location

(hereafter referred to as “Facility”) McKee Run Generating Station

Plant Mailing Address

McKee Run Generating Station


880 Buttner Place Dover, Delaware 19904


880 Buttner Place Dover, Delaware 19904

The nature of business of the Facility is Electrical Power Generation. The Standard Industrial Classification

code is 4911 - Electric Services. The North American Industry Classification System code is 221112.

_____________________________________ __________________________________

Jordan G. Matthews, P.E. / <Date> Angela D. Marconi, P.E., BCEE / <Date> Engineer Program Manager

Engineering & Compliance Branch Engineering & Compliance Branch (302) 739-9402 (302) 323-4542

Permit: AQM-001/00002 (Renewal 4) City of Dover McKee Run Generating Station

Draft/Proposed 7 DE Admin. Code 1130 Operating Permit Date

Page 2

Table of Contents

Condition Title Page

1 Emission Unit Identification 3

a Emission Units 3

b 7 DE Admin. Code 1102 Permits 3

2 General Requirements 3

a Certification 3

b Compliance

Error!

Bookmark

not

defined.

c Confidentiality 5

d Construction, Installation, or Alteration 5

e Definitions/Abbreviations 5

f Duty to Supplement 6

g Emissions Trading 6

h Fees 7

i Inspection and Entry Requirements 7

j Permit and Application Consultation 7

k Permit Availability 7

l Permit Renewal 7

m Permit Revision and Termination 8

n Permit Transfer 9

o Property Rights 9

p Risk Management Plan 9

q Protection of Stratospheric Ozone 10

r Severability 11

3 Specific Requirements 11

a Emission Limitations/Standards and/or Operational Limitations/Standards 11

b

Compliance Determination Methodology (Monitoring/Testing, QA/QC Procedures as applicable, and Record Keeping)

1. Specific Requirements 2. General Record Keeping Requirements

11

c

Reporting and Compliance Certification

1. Specific Reporting/Certification Requirements 2. General Reporting Requirements

3. General Compliance Certification Requirements

12

3- Table 1 Specific Requirements 166

a Emission Unit 3 -1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired

on Natural Gas or No. 2 Fuel Oil 166

b Emission Unit 4 & 5 - Two (2) 13.39 MMBTU/hr Hot Water Boilers; Fired on Natural Gas

46

c Emission Unit 6 & 7 - Two (2) Cold Solvent Cleaners 51

d Emission Unit 8 - 2,704,800 Gallon No. 2 Fuel Oil Storage Tank 54

e Facility Wide 55



Page 3

Table of Contents

Condition Title Page

f 7 DE Admin. Code 1136-Acid Rain Program 71

4 Operational Flexibility 72

5 Compliance Schedule 72

6 Permit Shield 72

Attachment A- Revision History 75

Condition 1- Emission Unit Identification

[Reference: 7 DE Admin. Code 1130 Section 3.3 dated 11/15/93]

a. Emission Units Information.


Emission Unit 3 1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on Natural

Gas or No. 2 Fuel Oil




b. 7 DE Admin. Code 1102 Permit Identification.

This table identifies the underlying permits whose provisions have been incorporated into this Title V

permit and specifies the reference number that will be used to identify the source of the underlying permit condition throughout this Title V permit.

Reference: Number Full 7 DE Admin. Code 1102 Permit Designation

APC-1981/1121-

OPERATION (Amendment 5)

APC-1981/1121-OPERATION (Amendment 5)(NOx RACT) dated xx/xx/xxxx

1,180 MMBTU/hr Riley Stoker Boiler; Fired on Natural Gas or No. 2 Fuel Oil (Emission Unit 3)

APC-1981/1122

(Amendment 1)

APC-1981/1122-OPERATION (Amendment 1) dated xx/xx/xxxx

13.39 MMBTU/hr Boiler Engineering and Supply Hot Water Boiler; Fired on Natural Gas (Emission Unit 4)

APC-1981/1123

(Amendment 1)

APC-1981/1122-OPERATION (Amendment 1) dated xx/xx/xxxx

13.39 MMBTU/hr Boiler Engineering and Supply Hot Water Boiler; Fired on Natural Gas (Emission Unit 4)

Condition 2 - General Requirements

a. Certification.

1. Each document submitted to the Department/EPA as required by this permit shall be certified by

a Responsible Official as to truth, accuracy, and completeness. Such certification shall be signed by a Responsible Official and shall contain the following language: “I certify, based on

information and belief formed after reasonable inquiry, the statements and information in the

document are true, accurate, and complete.” [Reference: 7 DE Admin. Code 1130 Section 5.6 dated



Page 4

Condition 2- General Requirements (Cont.)

11/15/93 and 6.3.1 dated 12/11/00]

2. Any report of deviations required under Conditions 3(c)(2)(ii) or 3(c)(2)(iii) that must be submitted to the Department within ten calendar days of discovery of the deviation, may be

submitted in the first instance without a certification provided a certification meeting the requirements of Condition 2(a)(1) is submitted to the Department within ten calendar days

thereafter, together with any corrected or supplemental information required concerning the

deviation. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.3.4 dated 12/11/00]

3. Each document submitted to the Department/EPA pursuant to this permit shall be sent to the

following addresses except as noted in Condition 2(a)(4):

State of Delaware – DNREC Division of Air Quality

State Street Commons

100 W. Water Street, Suite 6A Dover, DE 19904

ATTN: Division Director

U. S. Environmental Protection Agency Region III

Enforcement and Compliance Assurance Division (3ED21)

1650 Arch Street Philadelphia, PA 19103-2029

No. of Originals: 1 & No. of Copies:

1 No. of Copies: 1

4. In lieu of submitting a physical copy of the Compliance Certification report specified in Condition

3(c)(3) of this permit to the EPA, the Owner and/or Operator may, and is encouraged to, submit an electronic copy of the report to [email protected] as a PDF document. The

signed original annual General Certification report must be submitted to the Department at the address in Condition 2(a)(3).

b. Compliance.

1. The Owner and/or Operator shall comply with all terms and conditions of this permit. Any noncompliance with this permit constitutes a violation of the applicable requirements under the

Clean Air Act, and/or 7 DE Admin. Code 1100, and is grounds for an enforcement action; for permit termination, revocation, and reissuance or modification; or for denial of a permit renewal. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.1 dated 12/11/00]

2.

i. For applicable requirements with which the source is in compliance, the Owner and/or

Operator shall continue to comply with such requirements. [Reference: 7 DE Admin. Code 1130 Sections 5.4.8.3.1 dated 11/15/93 and 6.3.3 dated 12/11/00]

ii. For applicable requirements that will become effective during the term of this permit, the Owner and/or Operator shall meet such requirements on a timely basis unless a more

detailed schedule is expressly required by the applicable requirement. [Reference: 7 DE Admin. Code 1130 Sections 5.4.8.3.2 dated 11/15/93 and 6.3.3 dated 12/11/00]

3. Nothing in Condition 2(b)(1) of this permit shall be construed to preclude the Owner and/or Operator from making changes consistent with Condition 2(m)(3) [Minor Permit Modifications]

or Condition 4(a) [Operational Flexibility]. [Reference: 7 DE Admin. Code 1130 Sections 6.8 dated 12/11/00 and 7.5.1.5 dated 12/11/00]

4. The fact that it would have been necessary to halt or reduce an activity in order to maintain

compliance with the terms and conditions of this permit shall not constitute a defense for the Owner and/or Operator in any enforcement action. Nothing in this permit shall be construed as

precluding consideration of a need to halt or reduce activity as a mitigating factor in assessing

mailto:[email protected]



Page 5


penalties for noncompliance if the health, safety, or environmental impacts of halting or

reducing operations would be more serious that the impacts of continuing operations. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.2 dated 12/11/00]

5. The Owner and/or Operator may seek to establish that noncompliance with a technology-based emission limitation under this permit was due to an emergency or malfunction if both the record

keeping requirements in Condition 3(b)(2)(iii) and the reporting requirements in Condition

3(c)(2)(ii)(A) are satisfied. [Reference: 7 DE Admin. Code 1130 Section 6.7.2 dated 12/11/00]

6.

i. In any enforcement proceeding, the Owner and/or Operator seeking to establish the

occurrence of an emergency or malfunction has the burden of proof. [Reference: 7 DE Admin. Code 1130 Section 6.7.4 dated 12/11/00]

ii. The provisions of 7 DE Admin. Code 1130 pertaining to Emergency/Malfunctions as defined in Conditions Nos. 2(b)(5); 2(b)(6); 3(b)(2)(iii); and 3(c)(2)(ii)(A) of this permit are in

addition to any emergency or malfunction provision contained in any applicable requirement. [Reference: 7 DE Admin. Code 1130 Section 6.7.5 dated 12/11/00]

7. Reserved.

8. If required, the schedule of compliance in Condition 5 of this permit is supplemental to and shall not sanction noncompliance with the applicable requirements upon which it is based. [Reference: 7 DE Admin. Code 1130 Section 5.4.8.3.3 dated 11/15/93]

9. Nothing in this permit shall be interpreted to preclude the use of any credible evidence to

demonstrate noncompliance with any term of this permit. [Reference: 62 FR 8314 dated 2/24/97]

10. All terms and conditions of this permit are enforceable by the Department and by the U.S.

Environmental Protection Agency (“EPA”) unless specifically designated as “State Enforceable

Only” [Reference: 7 DE Admin. Code 1130 Section 6.2.1 dated 12/11/00]

c. Confidentiality. The Owner and/or Operator may make a claim of confidentiality for any

information or records submitted to the Department. However, by submitting a permit application, the Owner and/or Operator waives any right to confidentiality as to the contents of its permit, and

the permit contents will not be entitled to protection under 7 Del. C., Ch 60, § 6014. [Reference: 7 DE Admin. Code 1130 Sections 5.1.4 dated 11/15/93, 6.1.3.3.5 dated 12/11/00, and 6.1.7.5 dated 12/11/00]

1. Confidential information shall meet the requirements of 7 Del. C., Ch 60, § 6014, and 29 Del.

C., Ch 100. [Reference: 7 DE Admin. Code 1130 Section 5.1.4 dated 11/15/93]

2. If the Owner and/or Operator submits information to the Department under a claim of

confidentiality, the Owner and/or Operator shall also submit a copy of such information directly to the EPA, if the Department requests that the Owner and/or Operator do so. [Reference: 7 DE Admin. Code 1130 Section 5.1.4 dated 11/15/93]

d. Construction, Installation, or Alteration. The Owner and/or Operator shall not initiate

construction, installation, or alteration of any equipment or facility or air contaminant control device

which will emit or prevent the emission of an air contaminant prior to submitting an application to the Department under 7 DE Admin. Code 1102, and, when applicable, 7 DE Admin. Code No. 1125,

and receiving approval of such application from the Department; except as exempted in 7 DE Admin. Code 1102 Section 2.2. [Reference: 7 DE Admin. Code 1102 Section 2.1 dated 6/1/97 and 7 DE Admin. Code 1130 Section 7.2.3 dated 12/11/00]

e. Definitions/Abbreviations. Except as specifically provided for below, for the purposes of this

permit, terms used herein shall have the same meaning accorded to them under the applicable

requirements of the Clean Air Act and 7 DE Admin. Code 1100.



Page 6


1. “Act” means the Clean Air Act, as amended by the Clean Air Act Amendments of November 15,

1990, 42 U.S.C. 7401 et seq. [Reference: 7 DE Admin. Code 1130 Section 2 dated 11/15/93]

2. “AP-42” means the Compilation of Air Pollutant Emission Factors, Fifth Edition, AP-42, dated

January 15, 1995, as amended with Supplements and Updates.

3. “CFR” means Code of Federal Regulations.

4. “Emergency” means any situation arising from sudden and reasonably unforeseeable events

beyond the control of the sources, including acts of God, which situation requires immediate corrective action to restore normal operation, and that causes the source to exceed a

technology-based emission limitation under this permit, due to unavoidable increases in emissions attributable to the emergency. An emergency shall not include noncompliance to the

extent caused by improperly designed equipment, lack of preventative maintenance, careless or

improper operation, or operator error. [Reference: 7 DE Admin. Code 1130 Section 6.7.1 dated 12/11/00]

5. “Malfunction” means any sudden and unavoidable failure of air pollution control equipment or of

a process to operate in a normal or usual manner, and that causes the source to exceed a technology-based emission limitation under this permit, due to unavoidable increases in

emissions attributable to the malfunction. A malfunction shall not include noncompliance to the extent caused by improperly designed equipment, lack of preventative maintenance, careless or

improper operation, or operator error. [Reference: 7 DE Admin. Code 1130 Section 6.7.1 dated 12/11/00]

6. “Number 2 fuel oil” and “No. 2 fuel oil” means distillate oil.

7. “Reg.” and “Regulation” mean the regulations covered under 7 DE Admin. Code 1100.

8. “Regulations Governing the Control of Air Pollution” means the codification of those regulations enacted by the Delaware Department of Natural Resources and Environmental Control, in

accordance with 7 Del. C., Ch 60, § 6010.

f. Duty to Supplement.

1. Upon becoming aware of a failure to submit any relevant facts or a submittal of incorrect

information in any permit application, the Owner and/or Operator shall promptly submit to the Department such supplementary facts or corrected information. [Reference: 7 DE Admin. Code 1130 Section 5.2 dated 11/15/93]

2. The Owner and/or Operator shall promptly submit to the Department information as necessary

to address any requirements that become applicable to the source after the date it filed a

complete application but prior to the release of a corresponding draft permit. [Reference: 7 DE Admin. Code 1130 Section 5.2 dated 11/15/93]

3. The Owner and/or Operator shall furnish to the Department, upon receipt of a written request

and within a reasonable time specified by the Department:

i. Any information that the Department determines is reasonably necessary to evaluate or take final action on any permit application submitted in accordance with Condition 2(l) or 2(m) of

this permit. The Owner and/or Operator may request an extension to the deadline the

Department may impose on the response for such information. [Reference: 7 DE Admin. Code 1130 Section 5.1.2.3 dated 11/15/93]

ii. Any information that the Department requests to determine whether cause exists to modify, terminate, or revoke this permit, or to determine compliance with the terms and conditions of

this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.5 dated 12/11/00]



Page 7


iii. Copies of any records required to be kept by this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.5.7 dated 12/11/00]

g. Emission Trading. No permit revision shall be required under any approved economic incentives,

marketable permits, emissions trading, and other similar programs or processes for changes that are

provided for in the permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.9 dated 12/11/00]

h. Fees. The Owner and/or Operator shall pay fees to the Department consistent with the fee schedule

established by the Delaware General Assembly. [Reference: 7 DE Admin. Code 1130 Section 6.1.8 dated 12/11/00 and Section 9.0 dated 11/15/93]

i. Inspection and Entry Requirements. Upon presentation of identification, the Owner and/or

Operator shall allow authorized officials of the Department to perform the following:

1. Enter upon the Owner and/or Operator’s premises where a source is located or an emissions-related activity is conducted, or where records that must be kept under the terms and conditions

of this permit are located. [Reference: 7 DE Admin. Code 1130 Section 6.3.2.1 dated 12/11/00]

2. Have access to and copy, at reasonable times, any records that must be kept under the terms

and conditions of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.3.2.2 dated 12/11/00]

3. Inspect, at reasonable times and using reasonable safety practices, any facility, equipment (including monitoring and air pollution control equipment), practice, or operation regulated or

required under this permit. [Reference: 7 DE Admin. Code 1130 Section 6.3.2.3 dated 12/11/00]

4. Sample or monitor, at reasonable times, any substance or parameter for the purpose of assuring

compliance with this permit or any applicable requirement. [Reference: 7 DE Admin. Code 1130 Section 6.3.2.4 dated 12/11/00]

j. Permit and Application Consultation. The Owner and/or Operator is encouraged to consult with

Department personnel before submitting an application or, at any other time, concerning the operation, construction, expansion, or modification of any installation, or concerning the required

pollution control devices or system, the efficiency of such devices or system, or the pollution problem

related to the installation. [Reference: 7 DE Admin. Code 1130 Section 5.1.1.7 dated 11/15/93]

k. Permit Availability. The Owner and/or Operator shall have available at the facility at all times a

copy of this permit and shall provide a copy of this permit to the Department upon request. [Reference: 7 DE Admin. Code 1102 Section 8.1 dated 6/1/97]

l. Permit Renewal. This permit expires on <maximum is no more than the issue date plus 5 years>

except as provided in Condition 2(l)(4) below. [Reference: 7 DE Admin. Code 1130 Section 6.1.2 dated 12/11/00]

1. Applications for permit renewal shall be subject to the same procedural requirements, including those for public participation, affected state comment, and EPA review, that apply to initial

permit issuance under 7 DE Admin. Code 1130 Section 7.1, except that an application for

permit renewal may address only those portions of the permit that the Department determines require revision, supplementing, or deletion, incorporating the remaining permit terms by

Reference: from the previous permit. The Department may similarly, in issuing a draft renewal permit or proposed renewal permit, specify only those portions that will be revised,

supplemented, or deleted, incorporating the remaining permit terms by Reference:. [Reference: 7 DE Admin. Code 1130 Section 7.3.1 dated 12/11/00]

2. The Owner and/or Operator’s right to operate shall cease upon the expiration date unless a

timely and complete renewal application has been submitted to the Department no later than twelve (12) months prior to the permit expiration date. [Reference: 7 DE Admin. Code 1130 Section 7.3.2 dated 12/11/00]



Page 8


3. The Department shall review each application for completeness and shall inform the applicant

within 60 days of receipt if the application is incomplete. Unless the Department requests additional information or otherwise notifies the applicant of incompleteness within 60 days of an

application, an application will be deemed complete if it contains the information required by the application form and 7 DE Admin. Code 1130 Section 5.4. [Reference: 7 DE Admin. Code 1130 Section 5.1.2.1 dated 11/15/93

4. If a timely and complete application for a permit renewal is submitted to the Department pursuant to 7 DE Admin. Code 1130, Section 5.1.2.4 (dated 11/15/93) and Section 7.3.1

(dated 12/11/00) and the Department, through no fault of the Owner and/or Operator, fails to take final action to issue or deny the renewal permit before the end of the term of this permit,

then this permit shall not expire until the renewal permit has been issued or denied, and any permit shield granted for the permit shall continue in effect during that time. [Reference: 7 DE Admin. Code 1130 Section 7.3.3 dated 12/11/00]

m. Permit Revision and Termination.

1.

i. This permit may be modified, revoked, reopened, and reissued, or terminated for cause. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.3 dated 12/11/00]

ii. Except as provided under Condition 2(m)(3) [“Minor Permit Modification”], the filing of a request by the Owner and/or Operator for a permit modification, revocation and reissuance,

or termination, or of a modification of planned changes or anticipated noncompliance does not stay any term or condition of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.3 dated 12/11/00 and 7.5.1.5 dated 12/11/00]

2. “Administrative Permit Amendment.” When required, the Owner and/or Operator shall submit to the Department a request for an administrative permit amendment in accordance with 7 DE

Admin. Code 1130 Section 7.4. [Reference: 7 DE Admin. Code 1130 Section 7.4 dated 12/11/00]

3. “Minor Permit Modification.” When required, the Owner and/or Operator shall submit to the

Department an application for a minor permit modification in accordance with 7 DE Admin. Code 1130 Section 7.5.1 and 7.5.2. [Reference: 7 DE Admin. Code 1130 Section 7.5.1 dated 12/11/00 and 7.5.2 dated 12/11/00]

i. For a minor permit modification, during the period of time between the time the Owner and/or Operator makes the change or changes proposed in the minor permit modification

application and the time that the Department takes action on the application, the Owner and/or Operator shall comply with both the applicable requirements governing the change

and the proposed permit terms and conditions. During this period the Owner and/or Operator, at its own risk, need not comply with the existing terms and conditions of this

permit that it seeks to modify. [Reference: 7 DE Admin. Code 1130 Section 7.5.1.5 dated 12/11/00 and 7.5.2.5 dated 12/11/00]

ii. If the Owner and/or Operator fail to comply with its proposed permit terms and conditions

during this time period, the existing terms and conditions of this permit may be enforced against the Owner and/or Operator. [Reference: 7 DE Admin. Code 1130 Section 7.5.1.5 dated 12/11/00 and 7.5.2.5 dated 12/11/00]

4. “Significant Permit Modification.” When required, the Owner and/or Operator shall submit to the

Department an application for a significant permit modification in accordance with 7 DE Admin.

Code 1130 Section 7.5.3. [Reference: 7 DE Admin. Code 1130 Section 7.5.3 dated 12/11/00]



Page 9


5.

i. When the Owner and/or Operator is required to meet the requirements under Section 112(g) of the Act or to obtain a preconstruction permit under 7 DE Admin. Code 1100, the Owner

and/or Operator shall file a complete application to revise this permit within 12 months of commencing operation of the construction or modification. [Reference: 7 DE Admin. Code 1130 Section 5.1.1.4 dated 11/15/93]

ii. When the Owner and/or Operator is required to obtain a preconstruction permit, the Owner and/or Operator may submit an application to revise this permit for concurrent processing.

The revision request for this permit when submitted for concurrent processing shall be submitted to the Department with the Owner and/or Operator’s preconstruction review

application or at such later time as the Department may allow. Where this permit would prohibit such construction or change in operation, the Owner and/or Operator shall obtain a

permit revision before commencing operation. [Reference: 7 DE Admin. Code 1102 Sections 11.2.10, 11.5 and 12.4, dated 6/11/06, and 7 DE Admin. Code 1130 Section 5.1.1.4 dated 11/15/93]

iii. Where an application is not submitted for concurrent processing, the Owner and/or Operator

shall obtain an operating permit under 7 DE Admin. Code 1100 prior to commencing operation of the construction or modification to cover the period between the date operation

is commenced and until such time as operation is approved under 7 DE Admin. Code 1130. [Reference: 7 DE Admin. Code 1102 Section 2.1 dated 6/11/06]

6. “Permit Termination.” The Owner and/or Operator may at any time apply for termination of this permit in accordance with 7 DE Admin. Code 1130 Section 7.8.4 or Section 7.8.5. [Reference: 7 DE Admin. Code 1130 Sections 7.8.4 dated 12/11/00 and 7.8.5 dated 12/11/00]

n. Permit Transfer.

1. A change in ownership or operational control of this facility shall be treated as an administrative

permit amendment where the Department has determined that no other change in the permit is necessary, provided that a written agreement containing a specific date for transfer of permit

responsibility, coverage, and liability between the current and new owner has been submitted to

the Department. [Reference: 7 DE Admin. Code 1130 Section 7.4.1.4 dated 12/11/00]

2. In addition to any written agreement submitted by the Owner and/or Operator in accordance

with Condition 2(n)(1), the Owner and/or Operator shall have on file at the Department a statement meeting the requirements of 7 Del. C., Ch 79, Section 7902. This permit condition is state enforceable only. [Reference: 7 Del. C., Ch 79 Section 7902 dated 8/28/2007]

3. The written agreement required in Condition 2(n)(1) of this permit shall be provided to the

Department within a minimum of 30 calendar days prior to the specific date for transfer and

shall indicate that the transfer is agreeable to both the current and new owner. [Reference: 7 DE Admin. Code 1102 Section 7.1 dated 6/1/97]

o. Property Rights. This permit does not convey any property rights of any sort, or any exclusive

privilege. [Reference: 7 DE Admin. Code 1130 Section 6.1.7.4 dated 12/11/00]

p. Risk Management Plan Submissions.

1. In the event this stationary source, as defined in the State of Delaware 7 DE Admin. Code

1201 “Accidental Release Prevention Regulation” Section 4.0, is subject to or becomes subject to

Section 5.0 of 7 DE Admin. Code 1201 (as amended March 11, 2006), the owner or operator shall submit a risk management plan (RMP) to the Environmental Protection Agency’s RMP

Reporting Center by the date specified in Section 5.10 and required revisions as specified in Section 5.190. A certification statement shall also be submitted as mandated by Section 5.185.



Page 10


[Reference: 7 DE Admin. Code 1130 Section 6.1.4 dated 12/11/00, 7 DE Admin. Code 1201 as amended March 11,

2006 and Delaware; Approval of Accidental Release Prevention Program, Federal Register Vol. 6, No. 11 pages 30818-

22 dated June 8, 2001]

2. If this stationary source, as defined in 7 DE Admin. Code 1201 Section 4.0, is not subject to

Section 5.0 but is subject or becomes subject to Section 6.0 (as amended March 11, 2006), the

owner or operator shall submit a Delaware RMP to the State of Delaware’s Accidental Release Prevention group by the date as specified in Section 6.6.10 and required revisions as specified

by Section 6.6.1. Note: State enforceable only. [Reference: 7 DE Admin. Code 1201 as amended March 11, 2006]

q. Protection of Stratospheric Ozone.

When applicable, this Facility shall comply with the following requirements: [Reference: 40 CFR Part 82 “Protection of Stratospheric Ozone” revised as of 7/1/97 and 7 DE Admin. Code 1130 Section 2.0 dated 11/15/93]

1. The permittee shall comply with the standards for labeling of products using ozone-depleting

substances pursuant to 40 CFR Part 82, Subpart E:

i. All containers in which a class I or class II substance is stored or transported, all products containing a class I substance, and all products directly manufactured with a process that

uses a class I substance must bear the required warning statement if it is being introduced

into interstate commerce pursuant to §82.106.

ii. The placement of the required warning statement must comply with the requirements

pursuant to §82.108.

iii. The form of the label bearing the required warning statement must comply with the

requirements pursuant to §82.110.

iv. No person may modify, remove, or interfere with the required warning statement except as

described in §82.112.

2. Any person servicing, maintaining, or repairing appliances, except for motor vehicles, shall comply with the standards for recycling and emissions reduction pursuant to 40 CFR Part 82,

Subpart F, except as provided for Motor Vehicle Air Conditioners (MVACs) in Subpart B. In addition, Subpart F applies to refrigerant reclaimers, appliance owners, and manufacturers of

appliances and recycling and recovery equipment.

i. Persons owning appliances for maintenance, service, repair, or disposal must comply with the

prohibitions and required practices pursuant to §82.154 and §82.156.

ii. Equipment used during the maintenance, service, repair, or disposal of appliances must

comply with the standards for recycling and recovery equipment pursuant to §82.158.

iii. Persons performing maintenance, service, repair, or disposal of appliances must be certified

by an approved technician certification program pursuant to §82.161.

iv. Persons performing maintenance, service, repair, or disposal of appliances must certify with

the Administrator pursuant to §82.158 and §82.162.

v. Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply with

record keeping requirements pursuant to §82.166. (“MVAC-like appliance” as defined at

§82.152)

vi. Persons owning commercial or industrial process refrigeration equipment must comply with

the leak repair requirements pursuant to §82.156.



Page 11


3. Owners/Operators of appliances normally containing 50 or more pounds of refrigerant must

keep records of refrigerant purchased and added to such appliances pursuant to 40 CFR Part 82,

Subpart F §82.166.

4. If the permittee manufactures, transforms, destroys, imports, or exports a class I or class II substance, the permittee is subject to all the requirements as specified in 40 CFR Part 82,

Subpart A, “Production and Consumption Controls”.

5. If the permittee performs a service on motor (fleet) vehicles when this service involves ozone-depleting substance refrigerant (or regulated substitute substance) in the MVAC, the permittee

is subject to all the applicable requirements as specified in 40 CFR Part 82, Subpart B, “Servicing

of Motor Vehicle Air Conditioners”.

i. The term “motor vehicle” as used in Subpart B does not include a vehicle in which final

assembly of the vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the air-tight sealed refrigeration system used as refrigerated cargo, or

system used on passenger buses using HCFC-22 refrigerant. These systems are regulated

under 40 CFR Part 82, Subpart F.

6. The permittee shall be allowed to switch from any ozone-depleting substance to any alternative that is listed as acceptable in the Significant New Alternatives Program (SNAP) promulgated

pursuant to 40 CFR Part 82, Subpart G, Significant New Alternatives Policy Program.

r. Severability. The provisions of this permit are severable. If any part of this permit is held invalid, the application of such part to other persons or circumstances and the remainder of this permit shall

not be affected thereby and shall remain valid and in effect. [Reference: 7 DE Admin. Code 1130 Section 6.1.6 dated 12/11/00]

Condition 3- Specific Requirements

a. Emission Limitations Emission Standards, Operational Limitations, and Operational Standards. The Owner and/or Operator shall comply with the limitations and standards detailed in Condition 3 – Table 1 of this

permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]

b. Compliance Determination Methodology (Monitoring, Testing, QA/QC Procedures, and Record

Keeping). The Owner and/or Operator shall maintain records of all required monitoring data and support

information for a period of at least five years from the date of the monitoring sample, measurement, report, or application. Support information includes all original strip-chart recordings, where appropriate, for continuous

monitoring instrumentation, and copies of all reports required by the permit. Where appropriate, the permit may specify that records may be maintained in computerized form. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.2 dated 12/11/00]

1.

i. Specific Requirements. The Owner and/or Operator shall comply with the operational limitations, monitoring, testing, and record keeping requirements detailed in Condition 3 – Table 1 which are in

addition to those in Conditions 3(b)(1)(ii) and 3(b)(2) of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.1 dated 12/11/00, 6.1.3.1 dated 12/11/00, and 6.1.10 dated 12/11/00]

ii. General Testing Requirements. Upon written request of the Department, the Owner and/or Operator

shall, at the Owner and/or Operator’s expense, sample the emissions of, or fuel used by, an air contaminant emission source, maintain records, and submit reports to the Department on the results of

such sampling. [Reference: 7 DE Admin. Code 1117 Section 2.2 dated 7/17/84]

2. General Record Keeping Requirements. The Owner and/or Operator shall record, at a minimum,

all of the following information:



Page 12

Condition 3- Specific Requirements (Cont.)

i. If required, for each operating scenario identified in Condition 3 – Table 1 of this permit, a log that

indicates the operating scenario under which each particular emission unit is operating. The Owner and/or Operator shall, contemporaneously with changing from one operating scenario to another,

record in this log the time at which the operating scenario under which it is operating is changed. [Reference: 7 DE Admin. Code 1130 Section 6.1.10 dated 12/11/00]

ii. The following information to the extent specified in Condition 3 – Table 1 of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1 dated 12/11/00]

A. The date, place, and time of the sampling or measurements. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.1 dated 12/11/00]

B. The dates analyses were performed. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.2 dated 12/11/00]

C. The Owner and/or Operator or entity that performed the analyses. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.3 dated 12/11/00]

D. The analytical techniques or methods used. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.4 dated 12/11/00]

E. The results of such analyses. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.5 dated 12/11/00]

F. The operating conditions as existing at the time of sampling or measurement. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.2.1.6 dated 12/11/00]

iii. If the Owner and/or Operator is claiming the affirmative defense of emergency or malfunction as

provided in Condition 2(b)(5); a properly signed, contemporaneous operating logs, or other relevant

evidence which indicates that: [Reference: 7 DE Admin. Code 1130 Section 6.7.3 dated 12/11/00]

A. An emergency or malfunction occurred and the causes of the emergency or malfunction. [Reference: 7 DE Admin. Code 1130 Section 6.7.3.1 dated 12/11/00]

B. The facility was at the time of the emergency or malfunction being operating in a prudent and

professional manner and in compliance with the generally accepted industry operations and

maintenance procedures. [Reference: 7 DE Admin. Code 1130 Section 6.7.3.2 dated 12/11/00]

C. During the period of the emergency or malfunction the Owner and/or Operator took all reasonable

steps to minimize levels of emissions that exceeded the emission standards, or other requirements of

this permit. [Reference: 7 DE Admin. Code 1130 Section 6.7.3.3 dated 12/11/00]

iv. A copy of the written notice required by Condition 3(c)(2)(iii) for each change made under Condition 4(c) [Operational Flexibility] of this permit shall be maintained with a copy of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

c. Reporting and Compliance Certification Requirements.

1. Specific Reporting/Certification Requirements. The Owner and/or Operator shall comply with the

Reporting/Certification Requirements detailed in Condition 3– Table 1 of this permit, which are in addition to those of Conditions 3(c)(2) and 3(c)(3) of this permit. Each report that contains

any deviations from the terms of Condition 3– Table 1 shall identify the probable cause of the deviations and any corrective actions or preventative measures taken. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3 dated 12/11/00, 6.1.3.3.3.3 dated 12/11/00, and 6.1.3.3.3.4 dated 12/11/00]

2. General Reporting Requirements.

i. The Owner and/or Operator shall submit to the Department a report of any required monitoring not later than the first day of August (covering the period from January 1 through June 30 of the current

calendar year) and the first day of February (covering the period July 1 through December 31 of the

previous calendar year) of each calendar year. The first monitoring report due after the effective date



Page 13


of this permit should report on the monitoring requirements and compliance status with respect to this

permit for the entire semi-annual compliance period. Each report shall identify any deviations from the monitoring, record keeping, and reporting requirements under this permit; and the probable cause of

the deviations; and any corrective actions or preventative measures taken. If no deviations have occurred, such shall be stated in the report. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3.1 dated 12/11/00, 6.1.3.3.2 dated 12/11/00, and 6.1.3.3.3.4 dated 12/11/00]

ii. In addition to the semiannual monitoring reports required under Condition 3(c)(2)(i), the Owner and/or Operator shall submit to the Department supplemental written reports and/or notices identifying all

deviations from permit conditions, probable cause of the deviations, and any corrective actions or preventative measures as follows: [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3.3.3 dated 12/11/00 and 6.1.3.3.3.4 dated 12/11/00]

A. If the Owner and/or Operator is claiming the affirmative defense of emergency or malfunction as

provided in Condition 2(b)(5) of this permit, a notice of any deviation resulting from emergency or malfunction conditions shall be reported to the Department within two working days of the time

when the technology-based emission limitations were exceeded. Such notice shall contain a

description of the emergency or malfunction, any steps taken to mitigate emissions, and any corrective actions taken. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3.3.1 dated 12/11/00 and 6.7.3.4 dated 12/11/00]

B. Emissions in excess of any permit condition or emissions which create a condition of air pollution

shall be reported to the Department immediately upon discovery and after activating the appropriate site emergency plan, in the following manner: [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3.3.3 dated 12/11/00 and 6.1.3.3.3.2 dated 12/11/00]

1. Emissions that pose an imminent and substantial danger to public health, safety or the environment must be reported by calling the Department’s Environmental Emergency Notification

and Complaint number (800) 662-8802. [Reference: 7 DE Admin. Code No 1130, Section 6.1.3.3.3.2 dated 12/11/2000]

2. Emissions in excess of any permit condition or emissions which create a condition of air pollution but do not pose an imminent and substantial danger to public health, safety or the environment

must either be called in to the Environmental Emergency Notification and Complaint number (800)

662-8802 or faxed to (302) 855-1902. The ability to fax notifications to the Department may be revoked by the Department upon written notice to the Company and at the Department’s sole

discretion. [Reference: 7 DE Admin. Code No 1130, Section 6.1.3.3.3.2 dated 12/11/2000]

C. All emissions in excess of any permit condition or emissions which create a condition of air pollution

shall be reported to the Department in a written report pursuant to Condition 3(c)(2)(1) and/or the specific reporting requirements listed in Condition 3 – Table 1 of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.3.3.3 dated 12/11/00 and 6.1.3.3.3.4 dated 12/11/00]

D. Discharges to the atmosphere in excess of any quantity specified in the 7 DE Admin. Code 1203

(“Reporting of a Discharge of a Pollutant or an Air Contaminant”) shall be reported,

immediately upon discovery and after activating the appropriate site emergency plan, either in person or to the Department’s 24-hour Environmental Emergency Notification and Complaint line

(1-800-662-8802). Discharges in compliance with this permit and excess emissions previously reported under Condition 3(c)(2)(ii)(B) of this permit are exempt from this reporting requirement. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.3.3.5 dated 12/11/00 and 7DE Admin. Code 1203]

iii. Prior to making a change as provided in Condition 4 [Operational Flexibility] of this permit the Owner

and/or Operator shall give written notice to the Department and EPA at least seven calendar days

before the change is to be made. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]



Page 14


A. The seven day period may be shortened or eliminated as necessary for a change that must be

implemented more quickly to address unanticipated conditions posing a significant health, safety, or

environmental hazard. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

B. If less than seven calendar days notice is provided because of a need to respond more quickly to such unanticipated conditions, the Owner and/or Operator shall provide notice to the Department

and EPA as soon as possible after learning of the need to make the change, together with the

reasons why advance notice could not be given. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

C. The written notice shall include all of the following information: [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

1. The identification of the affected emission units and a description of the change to be made.

2. The date on which the change will occur.

3. Any changes in emissions.

4. Any permit terms and conditions that are affected, including any new applicable requirements.

iv. The Owner and/or Operator shall submit to the Department an annual emissions statement in

accordance with 7 DE Admin. Code 1117 Section 7.0 not later than April 30 of each year, or other date as established by the Department, unless an extension by the Department is granted. Such

emissions statement shall cover the preceding calendar year. [Reference: 7 DE Admin. Code 1117 Section 7 .0 dated 1/11/93]

v. If required, the Owner and/or Operator shall submit to the Department a progress report for applicable requirements identified in Condition 5 – Table 1 of this permit. Such reports shall be submitted not later

than the first day of August (covering the period from January 1 through June 30 of the current

calendar year) and the first day of February (covering the period July 1 through December 31 of the previous calendar year) of each calendar year. Each progress report shall include the following: [Reference: 7 DE Admin. Code 1130 Sections 5.4.8 dated 11/15/93 and 6.3.4 dated 12/11/00]

A. Dates for achieving the activities, milestones, or compliance required in the schedule of compliance,

and dates when such activities, milestones or compliance were achieved. [Reference: 7 DE Admin. Code 1130 Section 6.3.4.1 dated 12/11/00]

B. An explanation of why any dates in the schedule of compliance were not or will not be met, and any

preventive or corrective measures adopted. [Reference: 7 DE Admin. Code 1130 Section 6.3.4.2 dated 12/11/00]

vi. Nothing herein shall relieve the Owner and/or Operator from any reporting requirements under federal,

state, or local laws. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.3.3.5 dated 12/11/00]

3. General Compliance Certification Requirements.

i. Compliance with terms and conditions of this permit shall be certified to the Department not later than the first day of February of each year unless the terms or conditions in Condition 3– Table 1 of this

permit require compliance certifications to be submitted more frequently. Such certification shall cover

the previous calendar year and shall be submitted on Form AQM-1001BB. The Compliance Certification

shall include the following information: [Reference: 7 DE Admin. Code 1130 Section 6.3.5.1 dated 12/11/00]

A. The identification of each term or condition of the permit that is the basis of the certification. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.3.1 dated 12/11/00]

B. The Owner and/or Operator’s current compliance status, as shown by monitoring data and other information reasonably available to the Owner and/or Operator. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.3.2 dated 12/11/00]



Page 15


C. Such certification shall indicate whether compliance was continuous or intermittent during the

covered period. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.3.3 dated 12/11/00]

D. The methods used for determining the compliance status of the Owner and/or Operator, currently

and over the reporting period as required by the monitoring, record keeping, and reporting required

under Condition 3. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.3.4 dated 12/11/00]

E. Such other facts as the Department may require to determine the compliance status of the source. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.3.5 dated 12/11/00]

ii. Each compliance certification shall be submitted to the Department and EPA and shall be certified in

accordance with Condition 2(a) of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.3.5.4 dated 12/11/00]

iii. Any additional information possessed by the Owner and/or Operator that demonstrates noncompliance

with any applicable requirement must also be used as the basis for compliance certifications. [Reference: 62 CFR 8314 dated 2/24/97]

Draft/Proposed Permit: AQM-001/00002 (Renewal 4) City of Dover McKee Run Generating Station

7 DE Admin. Code 1130 Operating Permit Date

Page 16

CONDITION 3 – Table 1: Specific Requirements

Emission Limitations, Emission

Standards, Operational Limitations, & Operational Standards

Compliance Determination Methodology

(Monitoring, Testing, QA/QC Procedures, & Recordkeeping)


a. Emission Unit 3- 1,180 MMBTU/hr Riley Stoker Steam Generating Boiler; Fired on Natural Gas or No. 2 Fuel Oil

1. Particulate Matter (PM)

i. Emission Standard:

Emissions of filterable particulate matter (PMFilt) shall not exceed 0.075 pounds per

million British thermal units (MMBTU) heat input. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00 and Condition 2.1 of Permit: APC-1981/1121-Operation (Amendment 4) dated 05/07/10]

ii. Emission Limitation: Particulate matter, including both filterable

& condensable matter, with an

aerodynamic diameter less than or equal to a nominal 10 micrometers (PM10) shall

not exceed 54.85 tons on a rolling twelve (12) month basis. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]

iii. Operational Standard:

None

iv. Operational Limitation: None

v. Compliance Method:

A. Compliance with the emission standard established by Condition 3 – Table 1.a.1.i shall be demonstrated by

conducting Department-approved stack testing to determine the emission rate of filterable particulate

matter. 1. Testing shall be performed within five (5) years of the

anniversary of the most recent stack test; and

2. Subsequent stack tests shall continue on this schedule for the life of Emission Unit 3.

B. Compliance with the emission standard established by Condition 3 – Table 1.a.1.i shall be demonstrated by

estimating and recording emissions of PM10, in tons, on a

monthly and rolling twelve (12) month basis. Depending on the emission factor, the monthly and rolling twelve

(12) month PM10 emissions shall be calculated by taking the product of the following fuel-specific emission factor

and either the heat input contributed by the combustion of the fuel (No. 2 fuel oil), or the volume of fuel

combusted during the relevant period (natural gas). The

fuel-specific emission factors approved for use are: 1. 0.0585 pounds PM10 per million British thermal units

(MMBTU) contributed from No. 2 fuel oil combustion; and

2. 7.6 pounds PM10 per million standard cubic feet

(MMSCF) of natural gas combusted. [Reference 7 DE Admin. Code 1130 Section 6.1.3 dated 12/11/00]

vi. Monitoring:

The owner or operator shall monitor the following:

x. Reporting:

None in addition to that required by Conditions 2(a), 2(b)(9), 2(f)(3),

3(b)(1)(ii), and 3(c)(2) of this permit. [Reference :7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]

xi. Certification: None in addition to that required by

Condition 3(c)(3) of this permit. [Reference: 7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]


Draft/Proposed 7 DE Admin. Code 1130 Operating Permit Date Page 17

Condition 3 – Table 1: Specific Requirements (Continued)

Emission Limitations, Emission Standards, Operational Limitations, &

Operational Standards

Compliance Determination Methodology (Monitoring, Testing, QA/QC Procedures, &

Recordkeeping)


A. The period of time between stack testing of Emission Unit 3 to ensure that the compliance method requirements of

Condition 3 – Table 1.a.1.v.A are met.

B. The PM10 emissions from Emission Unit 3 on a monthly and rolling twelve (12) month basis pursuant to the

requirements of Condition 3 – Table 1.a.1.v.B. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing

In addition to the requirements of Conditions 3(b)(1)(ii) of

this permit, the owner or operator shall conduct performance test(s) pursuant to the requirements specified

in Condition 3 – Table 1.a.1.v.A and furnish the Department with a written report of the results of such performance

test(s) in accordance with the following general provisions:

A. One (1) original and one (1) copy of the test protocol shall be submitted a minimum of forty-five (45) days in

advance of the tentative test date to the address in Condition 4.1.3. The tests shall be conducted in

accordance with the State of Delaware and Federal requirements. [Reference 7 DE Admin. Code 1117 Section 2.2 dated 7/17/84]

B. The test protocol shall be approved by the Department prior to initiating any testing. Upon approval of the test

protocol, the Department will notify the owner or operator and the Company shall schedule a test date

with the source testing engineer. The Department must observe the test for the results to be considered for

acceptance. [Reference 7 DE Admin. Code 1102 Section 11.7 dated 06/11/06]

C. The final results of the testing shall be submitted to the

Department within sixty (60) days of the test completion. One (1) original and one (1) copy of the







Recordkeeping)


test report shall be submitted to the addresses below: [Reference 7 DE Admin. Code 1112 dated 11/24/93]

Original: Engineering & Compliance Branch

Attn: Permitting Engineer

State Street Commons 100 W. Water Street, Suite 6A

Dover, DE 19904

One (1) Copy to:

Engineering & Compliance Branch Attn: Source Testing Engineer

715 Grantham Lane New Castle, DE 19720

D. The final report of the results must meet the following requirements to be considered valid:

1. The full report shall include the emissions test report (including raw data from the test) as well as a

summary of the results and statement of compliance or non-compliance with permit conditions; [Reference 7 DE Admin. Code 1117 Section 2.6 dated 07/17/84]

2. Summary of Results and Statement of Compliance or Non-Compliance

The owner or operator shall supplement the report from the emissions testing firm with a summary that

includes the following information: (a) A statement that the owner or operator has

reviewed the report from the emissions testing

firm and agrees with the findings. [Reference 7 DE Admin. Code 1117 Section 2.6 dated 07/17/84]







Recordkeeping)


(b) Permit number(s) and condition(s) which are the basis for the compliance evaluation. [Reference 7 DE Admin. Code 1117 Section 2.6 dated 07/17/84]

(c) Summary of the results with respect to each

permit condition. [Reference 7 DE Admin. Code 1117 Section 2.6 dated 07/17/84]

(d) Statement of compliance or non-compliance with

each permit condition. [Reference 7 DE Admin. Code 1117 Section 2.6 dated 07/17/84]

3. The Test Report shall be certified by a Responsible Official as to truth, accuracy, and completeness. Such

certification shall be signed by a Responsible Official

and shall contain the following language: [Reference 7 DE Admin. Code 1130 Section 5.6 dated 11/15/93 and 6.3.1 dated 12/11/00]

“I certify, based on information and belief formed after

reasonable inquiry, the statements and information in the

document are true, accurate, and complete.”

E. The results must demonstrate to the Department’s satisfaction that the emission unit is operating in

compliance with the applicable regulations and conditions of this permit; if the final report of the test

results shows non-compliance the owner or operator shall propose corrective action(s). Failure to

demonstrate compliance through the test may result in

enforcement action. [Reference 7 DE Admin. Code 1102 Section 11.3 dated 06/11/06]

viii. Quality Assurance/Quality Control

None.

ix. Recordkeeping:







Recordkeeping)


In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the following information shall be

recorded and maintained in a manner suitable for review and

comparison to the applicable limit, standard, restriction, or requirement: [Reference: 7 DE Admin Code 1130 Section 6.1.3.1.2 and 6.2.1 dated 12/11/00]

A. The results of performance stack testing conducted.

B. The monthly and rolling twelve (12) month emission estimates of PM10.

C. The calculation method used for estimating PM10

emissions, to include the equation(s), emission factors, and throughputs used.

2. Sulfur Dioxide (SO2)

i. Emission Standard None.

ii. Emission Limitation

SO2 emissions shall not exceed 3.88 tons

on a rolling twelve (12) month basis. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]

iii. Operational Standard None.

iv. Operational Limitation

A. Emission Unit 3 shall only combust

natural gas or No. 2 fuel oil. [Reference: 7 DE Admin Code 1130 Section 6.1.1 dated 12/11/00]

B. The sulfur content of the No. 2 fuel oil

combusted in Emission Unit 3 shall not

v. Compliance Method: A. Compliance with the emission limitation established by

Condition 3 – Table 1.a.2.ii shall be demonstrated by estimating and recording SO2 emissions, in tons, on a

monthly and rolling twelve (12) month basis. SO2

emissions shall be calculated on an hourly basis and summed to determine daily, monthly, and rolling twelve

(12) month emissions. Hourly, fuel-specific SO2 emissions shall be calculated as follows:

1. For No. 2 fuel oil combustion, Equation D-2 from

Section 3.1.1 of Appendix D to 40 CFR Part 75 shall be used to estimate the hourly emission rate of SO2 from

Emission Unit 3. This equation is shown below for reference: [Reference Section 3.1.1 of Appendix D to 40 CFR Part 75 dated 02/18/12]

𝑆𝑂2𝑟𝑎𝑡𝑒−𝑜𝑖𝑙 = 2.0 × 𝑂𝐼𝐿𝑟𝑎𝑡𝑒 × %𝑆𝑜𝑖𝑙

100.0

Where:

SO2rate-oil = Hourly mass emission rate of SO2 emitted from combustion of oil, lb/hr.

x. Reporting: None in addition to that required by

Conditions 2(a), 2(b)(9), 2(f)(3), 3(b)(1)(ii), and 3(c)(2) of this permit. [Reference :7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]

xi. Certification: None in addition to that required by

Condition 3(c)(3) of this permit. [Reference: 7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]







Recordkeeping)


exceed 0.0015% by weight, unless it was:

1. Received for use on or before June

30, 2017; and 2. Stored in Delaware prior to July 1,

2016. [Reference: 7 DE Admin Code 1108 Section 2.3.1 dated 07/11/13]

OILrate = Mass rate of oil consumed per hour during combustion, lb/hr.

%Soil = Percentage of sulfur by weight in the oil sampled during

each day of Emission Unit 3 operation. 2.0 = Ratio of lb SO2/lb S.

2. For natural gas combustion, Equation D-5 from

Section 3.3.2 of Appendix D to 40 CFR Part 75 shall be

used to estimate the hourly emission rate of SO2 from Emission Unit 3. This equation is shown below for

reference: [Reference Section 3.3.2 of Appendix D to 40 CFR Part 75 dated 02/18/12]

𝑆𝑂2𝑟𝑎𝑡𝑒 = 𝐸𝑅 × 𝐻𝐼𝑟𝑎𝑡𝑒 Where:

SO2rate = Hourly mass emission rate of SO2 from combustion of a gaseous fuel, lb/hr.

ER = SO2 emission rate from Section 2.3.1.1 of Appendix D to

40 CFR Part 75 (0.0006 lb/MMBTU). HIrate = Hourly heat input rate of a gaseous fuel, calculated

using procedures in Section 3.4.1 of Appendix D to 40 CFR Part 75, in MMBTU/hr.

B. Compliance with the restrictions on the type of fuel

permitted for combustion in Emission Unit 3 established by Condition 3 – Table 1.a.2.iv.A shall be demonstrated

by operating in-line flow meters to record the type and measure the flow of each fuel combusted by Emission

Unit 3 and automatically recording the data. 1. The in-line flow meters shall be properly operating and

recording the flow of fuel during all periods when

Emission Unit 3 is combusting fuel. [Reference §75.21(a) dated 02/18/12]

2. The in-line flow meters shall be installed, calibrated,







Recordkeeping)


and operated in accordance with the procedures and specifications contained in Sections 2.1.2 and 2.1.5 of

Appendix D to 40 CFR Part 75. [Reference Sections 2.1.2 and 2.1.5 of Appendix D to 40 CFR Part 75 dated 02/18/12]

3. Accuracy tests of the fuel flowmeters shall be

performed periodically in accordance with the requirements specified in Condition 3 – Table 1.a.2.vii.

C. Compliance with the operational limitation established by Condition 3 – Table.1.a.2.iv.B shall be demonstrated by

collecting fuel oil samples, testing the samples collected,

and maintaining documentation of these activities pursuant to the requirements of Condition 3 – Table

1.a.3.vii.

vi. Monitoring:

The owner or operator shall monitor the following: A. The SO2 emissions from Emission Unit 3 on a monthly

and rolling twelve (12) month basis pursuant to the requirements of Condition 3 – Table 1.a.2.v.A.

B. The operation, maintenance, and testing of the in-line fuel flowmeters pursuant to the requirements of

Condition 3 – Table 1.a.2.v.B.

C. The collection and testing of fuel oil samples pursuant to the requirements of Condition 3 – Table 1.a.2.v.C. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing

A. Accuracy tests of the fuel flowmeters shall be performed periodically in accordance with the following

requirements:

1. The accuracy of each fuel flowmeter shall be tested prior to its initial use and at least once every four (4)







Recordkeeping)


fuel flowmeter QA operating quarters, as defined in 40 CFR Part 72.2, thereafter.

2. If four (4) fuel flowmeter QA operating quarters do

not occur first, no more than 20 successive calendar quarters shall elapse after the quarter in which a fuel

flowmeter was last tested for accuracy without a subsequent flowmeter accuracy test having been

conducted.

3. The flowmeter accuracies shall be tested more frequently if required by manufacturer specifications.

4. Each fuel flowmeter shall meet the accuracy specification in Section 2.1.5 of Appendix D to 40 CFR

Part 75. 5. The required oil flowmeter accuracy testing shall be

performed in accordance with the procedures of either

Section 2.1.5.1 or 2.1.5.2 of Appendix D to 40 CFR Part 75.

6. Orifice-type gas flowmeters shall perform either: (a) Flowmeter accuracy testing using the procedures

in Section 2.1.5.2 of Appendix D to 40 CFR Part

75; or (b) A transmitter accuracy test for the initial

certification and once every four (4) fuel flowmeter QA operating quarters thereafter. A

primary element visual inspection shall be required

for the initial certification and once every twelve (12) calendar quarters thereafter, according to the

procedures in Sections 2.1.6.1 through 2.1.6.4 of Appendix D to 40 CFR Part 75 for periodic quality

assurance. 7. Notwithstanding the requirements of Section 2.1.6 to

Appendix D of 40 CFR Part 75, if the procedures of







Recordkeeping)


Section 2.1.7 (fuel flow-to-load test) of Appendix D to 40 CFR Part 75 are performed during each fuel

flowmeter QA operating quarter, subsequent to a

required flowmeter accuracy test or (if applicable) transmitter accuracy test and primary element

inspection, those procedures may be used to meet the requirement for periodic quality assurance testing for

a period of up to 20 calendar quarters from the

previous accuracy test or (if applicable) transmitter accuracy test and primary element inspection. [Reference Section 2.1.6 of Appendix D to 40 CFR Part 75 dated 02/18/12]

B. Fuel oil samples shall be collected pursuant to one of the

following methods from Table D-4 of Appendix D to 40 CFR Part 75:

1. Sample from the storage tank for Emission Unit 3 after each addition of oil to the storage tank, in accordance

with Section 2.2.4.2 of Appendix D to 40 CFR Part 75; 2. Sample from the fuel lot in the shipment tank or

container upon receipt of each oil delivery or from the

fuel lot in the oil supplier’s storage container, in accordance with Section 2.2.4.3 (fuel supplier

certification) of Appendix D to 40 CFR Part 75; 3. Use the flow proportional sampling methodology in

Section 2.2.3 of Appendix D to 40 CFR Part 75; or

4. Use the daily manual sampling methodology in Section 2.2.4.1 of Appendix D to 40 CFR Part 75. [Reference Table D-4 of Appendix D to 40 CFR Part 75 dated 02/18/12]

C. In the event that the owner or operator cannot use the

procedures specified in Condition 4.7.1, fuel samples shall be collected using one of the following methods:







Recordkeeping)


1. From the transport vessel for each shipment of distillate fuel oil received at the facility for combustion

in Emission Unit 3;

2. From the supply pipeline each day distillate oil is delivered to the facility via pipeline for combustion in

Emission Unit 3 after sufficient fuel oil has been drained from the sampling line to remove any fuel oil

that may have been standing in the sampling line; or

3. From the supply pipeline at the inlet to Emission Unit 3 each day it fires any quantity of fuel oil, after

sufficient fuel oil has been drained from the sampling line to remove any fuel oil that may have been

standing in the sampling line. [Reference 7 DE Admin. Code 1146 Section 5.5.51 dated 12/11/06]

D. The gross calorific value (GCV) of oil samples collected

shall be determined in accordance with one of the following procedures:

1. ASTM D240-00; 2. ASTM D4809-00;

3. ASTM D5865-01a; 4. ASTM D5865-10; or

5. Any other procedures listed in Section 5.5 of Appendix

F to 40 CFR Part 75. [Reference Section 2.2.7 of Appendix D to 40 CFR Part 75 dated 02/18/12]

E. Results from each oil sample analysis shall be available no later than thirty (30) calendar days after the sample is

composited or taken. During an audit, the Department may require that the results be available within 5

business days or sooner, if practicable. [Reference Section 2.2.8 of Appendix D to 40 CFR Part 75 dated 02/18/12]

F. The sulfur content of the fuel samples collected shall be

determined in accordance with one of the following methods:







Recordkeeping)


1. ASTM method D129; 2. ASTM method D1266;

3. ASTM method D1552;

4. ASTM method D2622; 5. ASTM method D4294; or

6. ASTM method D5453. [Reference 7 DE Admin. Code 1108 Section 5.5.2 dated 12/11/06]

G. In addition to the above requirements, the following information shall be obtained and maintained for each

shipment of fuel oil received:

1. The name, address, and telephone number of the fuel supplier (transferor);

2. The name, address, and telephone number of the transferee, and the address where the fuel oil is

delivered;

3. The volume of fuel being delivered, and the date of delivery; and

4. The type of fuel, and the sulfur content of the fuel as a delivered product, determined pursuant to one of

the sampling methods specified in Conditions 4.7.1 or 4.7.2 and testing methods specified in Condition 4.7.5,

and expressed as one of the following:

(a) The actual sulfur content in ppm or percent (%) by weight; or

(b) A statement that certifies the sulfur content of the shipment is equal to or below the limit specified in

Condition 3.1.2. [Reference: 7 DE Admin. Code 1108 Section 5.1, dated 07/11/13]

viii. Quality Assurance/Quality Control None in addition to those specified by Condition 3 – Table

1.a.2.vii.A.







Recordkeeping)


ix. Recordkeeping: In addition to the requirements of Conditions 3(b)(1)(ii) and

3(b)(2) of this permit, the following information shall be

recorded and maintained in a manner suitable for review and comparison to the applicable limit, standard, restriction, or

requirement: [Reference: 7 DE Admin Code 1130 Section 6.1.3.1.2 and 6.2.1 dated 12/11/00]

A. The monthly and rolling twelve (12) month emission estimates of SO2 pursuant to the requirements of

Condition 3 – Table 1.a.2.v.A.

B. The volume of natural gas and No. 2 fuel oil combusted in Emission Unit 3 recorded by the in-line flowmeters and

summarized on: 1. An hourly basis;

2. A monthly basis; and

3. A rolling twelve (12) month basis. C. Records of actions taken to install, calibrate, and operate

the in-line flowmeters pursuant to Condition 3 – Table 1.a.2.v.B.2 and the federal requirements referenced

therein. D. Records of the following as they pertain to natural gas

and No. 2 fuel oil flowmeter accuracy tests:

1. A record of each fuel flowmeter QA operating quarter achieved by Emission Unit 3, as this term is defined in

§72.2; 2. The date of each test performed;

3. The name of the individual and/or company

performing the test; 4. The section of Appendix D to 40 CFR Part 75 which

corresponds with the test performed; and 5. Any other information required to confirm compliance

with the applicable requirements under Appendix D to 40 CFR Part 75.







Recordkeeping)


E. Records of the following as they pertain to each No. 2 fuel oil sample collected and tested:

1. The date of sample collection;

2. The location where the fuel oil sample was collected; 3. The permit condition and/or requirement within

Appendix D to 40 CFR Part 75 with which the sampling was conducted in accordance;

4. The method used to determine the fuel sample GCV;

5. The GCV results of the sample; 6. The method used to determine the fuel sample sulfur

content; 7. The sulfur content results of the sample;

8. The number of days between sample collection and analysis results; and

9. The information required by Condition 4.7.6 for each

shipment of fuel oil received.

3. Visible Emissions

i. Emission Standard

A. Except during periods of startup, the emission of visible air contaminants

and/or smoke from Emission Unit 3 shall not possess a shade or

appearance greater than twenty

(20%) percent opacity for an aggregate of more than three (3)

minutes in any one (1) hour or more than fifteen (15) minutes in any

twenty-four (24) hour period. [Reference 7 DE Admin. Code 1114 Section 2.0 dated 11/11/13]

B. The emissions of visible air contaminants during start-up shall not

exceed forty (40) percent opacity as a

v. Compliance Method

A. Compliance with the opacity standards established by Conditions 2.2 and 2.3 shall be demonstrated by:

1. Properly maintaining and operating a COMS in accordance with the requirements of Performance

Specification 1 – Specifications and Test Procedures

for Opacity Continuous Emission Monitoring Systems in Stationary Sources, of Appendix B to 40 CFR Part 60

during all periods of combustion in Emission Unit 3; 2. Recording and maintaining records of the continuous

opacity measurements made by the COMS; and 3. Monitoring and recording the:

(a) Time of initial activation of any boiler fan (initial

activation); and

x. Reporting


3(b)(1)(ii), and 3(c)(2) of this permit. [Reference :7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]

xi. Certification

None in addition to that required by Condition 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.2.3 and 6.2.2 dated 12/11/2000]







Recordkeeping)


rolling six (6) minute average. Startup is defined as the period of time from

the initial activation of any boiler fan

(initial sequence) until Emission Unit 3 has been released to the grid for

dispatch (nominally 18 megawatts) when starting from an ambient

pressure state. [Reference 7 DE Admin. Code 1130 Section 6.1.1 and 6.2.1 dated 11/11/13]


None

iii. Operational Standard None

iv. Operational Limitations At all periods of Emission Unit 3 operation,

a Continuous Opacity Monitoring System (COMS), shall be properly operating in

accordance with Performance Specification

1 – Specifications and Test Procedures for Opacity Continuous Emission Monitoring

Systems in Stationary Sources, from Appendix B of 40 CFR Part 60. [Reference 7 DE Admin. Code 1117 Section 3.2.1 dated 07/17/84]

(b) Time when Emission Unit 3 is released to the grid for dispatch. [Reference 7 DE Admin. Code 1117 Section 3.2.1 dated 07/17/84 and 7 DE Admin. Code 1130 Section 6.1.3 dated 12/11/00]

B. Compliance with the requirements of Condition 3 – Table

1.a.3.iv shall be demonstrated by maintaining records: 1. Necessary to verify adherence to the requirements of

Performance Specification 1 – Specifications and Test Procedures for Opacity Continuous Emission

Monitoring Systems in Stationary Sources, from Appendix B of 40 CFR Part 60.

2. Of continuous opacity measurements. The COMS shall

complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each

successive 10-second period. 3. Of the zero and span drift checks in accordance with

the method prescribed by the manufacturer. The zero

and span drift checks shall occur at least once daily unless the manufacturer has recommended

adjustments at shorter intervals, in which case such recommendations shall be followed.

4. Indicating the span of the COMS. The COMS span

shall be approximately 200% of the expected instrument data display output corresponding to the

emission standard for Emission Unit 3. 5. Of any periods of COMS outage. [Reference 7 DE Admin.

Code 1117 Section 3.2.1 dated 07/17/84 and Appendix B of 40 CFR Part 60 dated 03/16/15]

vi. Monitoring

The owner or operator shall monitor the following: A. The operation and maintenance of the COMS pursuant to

the requirements of Condition 3 – Table 1.a.3.v.A.1.







Recordkeeping)


B. The opacity of the gas exhausting from Emission Unit 3’s stack to ensure compliance with the emission standards

established by Condition 3 – Table 1.a.3.i.A and Condition

3 – Table 1.a.3.i.B. C. The initial activation of any boiler fan and dispatch of

Emission Unit 3 to the grid to ensure compliance with the opacity standard established by Condition 3 – Table

1.a.3.i.B.

D. The zero and span drift checks to ensure they are conducted in accordance with the requirements of

Condition 3 – Table 1.a.3.v.B.3. E. Periods of COMS outage. [Reference 7 DE Admin. Code 1130

Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing None in addition to that required by Condition 3(b)(1)(ii) of this permit.


None. ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the following information related to

the COMS shall be recorded and maintained in a manner suitable for review and comparison to the applicable limit,

standard, restriction, or requirement:

A. All records required to verify compliance with the applicable requirements of Performance Specification 1 of

Appendix B to 40 CFR Part 60; B. Records of continuous opacity measurements collected;

C. Records of zero and span drift checks;







Recordkeeping)


D. The COMS manufacturer’s recommendations for conducting zero and span drift checks;

E. The COMS span;

F. Records of any periods of COMS outage; G. Results of COMS performance testing;

H. The technical specifications for the COMS; I. Any maintenance or repairs performed on the COMS; and

J. With regards to Emission Unit 3’s start-up period:

1. Time of initial activation of any boiler fan (initial activation); and

2. Time when Emission Unit 3 is released to the grid for dispatch. [Reference: 7 DE Admin Code 1130 Section 6.1.3.1.2 and 6.2.1 dated 12/11/00]

4. Nitrogen Oxides (NOX)


NOX emissions from Emission Unit 3 shall not exceed 0.307 pounds per MMBTU on a

calendar-day basis. [Reference 7 DE Admin. Code 1112 Section 3.2.2 dated 11/24/93]

ii. Emission Limitation NOX emissions from Emission Unit 3 shall

not exceed: A. 2.93 tons per calendar-day during the

ozone control period (May 1-

September 30); and B. 244.0 tons on a rolling twelve (12)

month basis. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]

iii. Operational Standard

None

v. Compliance Methodology

A. Compliance with the NOX emission limitations and standards established by Condition 3 – Table 1.a.4.i,

Condition 3 – Table 1.a.4.ii.A, and Condition 3 – Table

1.a.4.ii.B shall be demonstrated by maintaining records of the following:

1. The operation of Emission Unit 3 with low excess air, low NOX burner technology, and opened overfire air

damper, to the extent practicable, at all times; and [Reference 7 DE Admin. Code 1130 Section 6.1.3 dated 12/11/00]

2. The operation and maintenance of a CEMS for the

measurement of NOX in accordance with the applicable requirements of 40 CFR Part 75 Continuous Emission Monitoring: (a) The emissions measured by the CEMS shall be

recorded and organized in a manner suitable for

review and comparison to the standards and limitations of Condition 2.1.3. This shall include

NOX emissions summarized:

x. Reporting

In addition to the requirements of Conditions 2(a), 2(b)(9), 2(f)(3),

3(b)(1)(ii), and 3(c)(2) of this permit,

the owner or operator shall submit the following reports as they apply:

A. The owner or operator shall submit a report to the Department within thirty

(30) days of becoming aware of NOX

emissions in excess of 0.307 lb/MMBTU based upon a rolling

twenty-four (24) average. The report shall contain: [Reference 7 DE Admin. Code 1112 Section 7.3 dated 11/24/93] 1. The name and location of the

facility.

2. The subject source(s) that caused the excess emissions.







Recordkeeping)


iv. Operational Limitation A. Emission Unit 3 shall operate on low

excess air with low NOX burner

technology and an opened overfire air damper at all times, and maintain

them in accordance with the manufacturer’s recommendations. [Reference 7 DE Admin. Code 1112 Section 3.2.2.1 dated 11/24/93]

B. At all periods of Emission Unit 3 operation a Continuous Emissions

Monitoring System (CEMS) for the

measurement of NOX shall be operating in accordance with 40 CFR

Part 75 Continuous Emission Monitoring. [Reference 7 DE Admin. Code 1112 Section 3.2.4.1 dated 11/24/93]

(i) On a lb/MMBTU basis for each calendar-day of operation;

(ii) In tons for each calendar-day during the

ozone control period (May 1-September 30); and

(iii) In tons, on a monthly and rolling twelve (12) month basis.

(b) In the event that NOX emissions from Emission

Unit 3 exceed 2.93 tons on more than three (3) calendar-days during the ozone control period of

any calendar year, a corrective action plan shall be initiated. [Reference 7 DE Admin. Code 1112 Sections 3.2.2.1 and 3.2.4.1 dated 11/24/93]

B. Compliance with the requirements of Condition 3 – Table

1.a.4.iv.A shall be demonstrated by maintaining records

of the installation, maintenance, and, to the extent practicable, operation of the low excess air, low NOX

burner, and overfire air damper. [Reference 7 DE Admin. Code 1112 Section 3.2.2.1 dated 11/24/93]

C. Compliance with the requirements of Condition 3 – Table 1.a.4.iv.B shall be demonstrated by maintaining records

of the NOX CEMS being operated, calibrated, and

maintained in accordance with the relevant quality assurance and quality control procedures of Appendix B

to 40 CFR Part 75. [Reference §75.21(a)(1) dated 03/28/11]

vi. Monitoring The owner or operator shall monitor the following:

A. The maintenance and operation of the low excess air, low

NOX burner, and overfire air damper. B. The calibration, maintenance, and operation of the NOX

CEMS to ensure it is complying with the applicable requirements of 40 CFR Part 75.

3. The time and date of first observation of the excess

emissions.

4. The cause and expected duration of the excess emissions.

5. For sources subject to numerical emission limitations, the estimated

rate of emissions (expressed in

units of the applicable emission limitation) and the operating data

and calculations used in determining the magnitude of the

excess emissions. 6. The proposed corrective actions

and schedule to correct conditions

causing the excess emissions. B. Within seven (7) days of becoming

aware that Emission Unit 3’s operation has triggered the corrective

action plan specified in Condition 3 –

Table 1.a.4.v.A.2.b, the Department shall be notified in writing: [Reference: 7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00] 1. Within 120 days of notification, the

owner or operator shall complete

and submit to the Department a corrective action plan including:

2. The proposed operational changes

and/or technology additions that will result in reducing NOX

emissions below the triggering action level of 2.93 tons daily







Recordkeeping)


C. The emissions of NOX from Emission Unit 3 in the units and timeframe specified by Condition 3 – Table

1.a.4.v.A.2.a to ensure compliance with the relevant

emission standards and limitations. Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing

None in addition to that required by Condition 3(b)(1)(ii) of this permit.

viii. Quality Assurance/Quality Control None in addition to those required under 40 CFR Part 75.

ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and

3(b)(2) of this permit, the following information shall be recorded and maintained in a manner suitable for review and

comparison to the applicable limit, standard, restriction, or requirement:

A. Documentation of the installation and operation of the low excess air, low NOX burner, and overfire air systems,

pursuant to the requirements of Condition 3 – Table

1.a.4.v.A.1 and Condition 3 – Table 1.a.4.v.B. B. NOX emissions recorded by the associated CEMS and

summarized pursuant to the requirements of Condition 3 – Table 1.a.4.v.A.1.a.

C. In the event that NOX emissions from Emission Unit 3

exceed 2.93 tons on more than three (3) calendar-days during the ozone control period, the owner or operator

shall maintain the information required by Condition 3 – Table 1.a.4.v.A.1.b, to include:

1. A copy of the required corrective action plan; and

mass emissions on more than three (3) days during the ozone

control period of May 1 through

September 30 on a calendar-day basis.

3. A schedule of implementation of the corrective action plan.

C. The Department shall review and

provide comments on the corrective action plan or grant approval within

sixty (60) days of receipt. [Reference Permit: APC-1981/1121-Operation (Amendment 5) dated xx/xx/xx]

xi. Certification None in addition to that required by

Condition 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.2.3 and 6.2.2 dated 12/11/2000]







Recordkeeping)


2. All actions taken in accordance with the requirements of the corrective action plan.

D. With regards to the NOX CEMS, the information required

to demonstrate compliance with the requirements of Appendix B to 40 CFR Part 75 shall be maintained in a

format suitable for review and comparison to the relevant requirements. This shall include, but is not limited to the

following:

1. For each daily and 7-day calibration error test, including any follow-up tests after corrective action:

(a) The component/system identification code; (b) Instrument span;

(c) Date and hour; (d) Reference value;

(e) Observed value

(f) Percent calibration error; and (g) Description of any adjustments, corrective actions,

or maintenance following tests. [Reference: §75.59(a)(1), dated 03/28/11]

2. For the initial and all subsequent linearity checks, including any follow-up tests after corrective action:

(a) The component/system identification code;

(b) Instrument span; (c) Date and hour;

(d) Reference value; (e) Observed value

(f) Percent calibration error; and

(g) Description of any adjustments, corrective actions, or maintenance following tests. [Reference: §75.59(a)(3), dated 03/28/11]

3. For the initial and all subsequent relative accuracy test

audits: (a) Date and hour;







Recordkeeping)


(b) Reference Method(s) used; and (c) Individual test run data from the relative accuracy

test audit for the flow monitor when (when

monitoring exhaust gas flow) and nitrogen oxide CEMS including:

(i) Date, hour, and minute of beginning of test run;

(ii) Date, hour, and minute of end of test run;

(iii) Component/system identification code; (iv) Run number;

(v) Run data for monitor; (vi) Run data for reference method; and

(vii) Flag value (0 or 1) indicating whether run has been used in calculating relative accuracy and

bias values. [Reference: §75.59(a)(5), dated 03/28/11]

5. Other Criteria Pollutants


None

ii. Emission Limitation A. VOC emissions from Emission Unit 3

shall not exceed 6.66 tons on a rolling

twelve (12) month basis. B. CO emissions from Emission Unit 3

shall not exceed 101.75 tons on a rolling twelve (12) month basis. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]


None


Compliance with the rolling twelve (12) month emission limits established by Condition 3 – Table 1.a.5.ii.A and

Condition 3 – Table 1.a.5.ii.B shall be demonstrated by estimating and recording emissions of VOCs, and CO, in

tons, on a monthly and rolling twelve (12) month basis. The

monthly and rolling twelve (12) month emissions of the pollutants shall be calculated by taking the product of the

applicable, fuel-specific emission factor from the following table and the volume of fuel combusted during the relevant

period. [Reference 7 DE Admin. Code 1130 Section 6.1.3 dated 12/11/00]

x. Reporting


3(b)(1)(ii), and 3(c)(2) of this permit. [Reference: 7 DE Admin Code 1130 Sections 6.1.3.2.3 and 6.2.1 dated 12/11/00]


Condition 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.2.3 and 6.2.2 dated 12/11/2000]







Recordkeeping)


iv. Operational Limitation None

Pollutant No. 2 Fuel Oil Natural Gas

Factor Units Source Factor Units Source

VOCs 0.2 #/103

Gallons

AP-42 Emission Factor

5.5 #/MMSCF AP-42

Emission Factor

CO 5 #/103

Gallons

AP-42 Emission Factor

84 #/MMSCF AP-42

Emission Factor

vi. Monitoring

The owner or operator shall monitor the emissions of VOCs and CO on a monthly and rolling twelve (12) month basis

pursuant to the requirements of Condition 3 – Table 1.a.5.v. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing None in addition to that required by Condition 3(b)(1)(ii) of

this permit.


None

ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the following information shall be

recorded and maintained in a manner suitable for review and comparison to the applicable limit, standard, restriction, or

requirement: [Reference: 7 DE Admin Code 1130 Section 6.1.3.1.2 and 6.2.1 dated 12/11/00] A. The monthly and rolling twelve (12) month emission

estimates of VOCs and CO.







Recordkeeping)


B. The calculation method used for estimating VOC and CO emissions, to include the equation(s), emission factors,

and throughputs used.

6. Allowable Operating Scenarios

i. Emission Standard None


None


iv. Operational Limitation A. Emission Unit 3 shall be operated

either as a “natural gas-fired electric utility steam generating unit” or under

the “limited-use liquid oil-fired

subcategory” as these terms are defined in §63.10042. [Reference: 7 DE Admin Code 1130 Section 6.8 dated 12/11/00]

B. If Emission Unit 3 is operated as a

“natural gas-fired electric utility steam generating unit”, the heat input

contributed by the combustion of No.

2 fuel oil shall not exceed: 1. 10.0 percent of the average annual

heat input during the previous 3 calendar years; or

2. 15.0 percent of the annual heat input during any one of those

calendar years. [Reference §63.10042 dated 04/06/16]

C. If Emission Unit 3 is operated under

the “limited-use liquid oil-fired

v. Compliance Methodology A. Emission Unit 3’s operating scenario shall be determined

by the heat input contributed by the combustion of No. 2 fuel oil, and comparing it to either the fuel heat input

contributed by the combustion of natural gas or Emission Unit 3’s maximum or nameplate heat input value, over

the relevant time periods as described by Condition 3 –

Table 1.a.6.iv.B and Condition 3 – Table 1.a.6.iv.C. For the purposes of these comparisons, the heat input

contributed by the combustion of each fuel shall be calculated as follows: [Reference Sections 5.5.1(a) and 5.5.2 of Appendix F to 40 CFR Part 74 dated 01/18/12] 1. The hourly heat input contributed by the combustion

of No. 2 fuel oil shall be calculated pursuant to

Equation F-19 in paragraph (a) to Section 5.5.1 of Appendix F to 40 CFR Part 75. This equation is as

follows:

𝐻𝐼𝑜 = 𝑀𝑜

𝐺𝐶𝑉𝑜

106

Where: HIo = Hourly heat input rate from oil, MMBTU/hr.

Mo = Mass rate of oil consumed per hour, as determined using procedures in Appendix D to 40 CFR Part 75, in lb/hr, tons/hr, or kg/hr.

GCVo = Gross calorific value of oil, as measured by ASTM D240-

00, ASTM-5865-01a, ASTM, D5865-10, or ASTM D4809-00 for each oil sample under Section 2.2 of Appendix D to 40 CFR Part 75, BTU/unit mass (all incorporated by reference under §75.6).

x. Reporting: In addition to the requirements of

Conditions 2(a), 2(b)(9), 2(f)(3), 3(b)(1)(ii), and 3(c)(2) of this permit, the

owner or operator shall submit the following reports as they apply:

A. At least thirty (30) days prior to

Emission Unit 3 commencing, or recommencing, operation that would

subject it to requirements under Subpart 5U to 40 CFR Part 63, the

owner or operator shall submit a

notification that identifies: 1. The name of the owner or

operator of the EGU, the location of the facility, the unit(s) that will

commence or recommence operations that will cause the

unit(s) to meet the definition of an

EGU subject to this subpart, and the date of the notice;

2. The 40 CFR part 60, part 62, or part 63 subpart and subcategory

currently applicable to your

unit(s), and the subcategory of this subpart that will be applicable

after you commence or recommence operation that will







Recordkeeping)


subcategory”, the heat input contributed by the combustion of No.

2 fuel oil shall be less than 8 percent

of Emission Unit 3’s maximum or nameplate heat input, whichever is

greater, averaged over a 24-month block contiguous period commencing

on the first of the month following the

compliance date specified in §63.9984. [Reference §63.10042 dated 04/06/16]

D. In the event that Emission Unit 3 is

operated under the “limited-use liquid oil-fired subcategory”, as the term is

defined in §63.10042, the applicable

requirements of Subpart 5U to 40 CFR Part 63 must be met. At the time of

writing this permit, the following requirements were deemed relevant

for inclusion: 1. An electric steam generating unit

that is considered an existing

source and does not meet the definition of an EGU subject to

Subpart 5U on April 16, 2015 must comply with the applicable existing

source provisions of Subpart 5U on

the date such unit meets the definition of an EGU subject to

Subpart 5U. [Reference §63.9984(d) dated 04/06/16]

2. Pursuant to §63.9991(a), the owner or operator must meet each

106 = Conversion of BTU to MMBTU

2. The heat input contributed by the combustion of

natural gas shall be calculated pursuant to Equation F-

20 in Section 5.5.2 to Appendix F of 40 CFR Part 75. This equation is as follows:

𝐻𝐼𝑔 = 𝑄𝑔 × 𝐺𝐶𝑉𝑔

106

Where: HIg = Hourly heat input rate from combustion of natural gas, MMBTU/hr.

GASrate = Metered flow rate of natural gas combusted during unit operation, 100 scf/hr.

GCVg = Gross calorific value of natural gas, as determined by

sampling (as verified by the contractual supplier at least once every month pipeline natural gas is combusted, as specified in

Section 2.3 of Appendix D to 40 CFR Part 75) using ASTM D1826-94 (Reapproved 1998), ASTM D3588-98, ASTM D4891-

89 (Reapproved 2006), GPA Standard 2172-96 Calculation of Gross Heating Value, Relative Density and Compressibility Factor

for Natural Gas Mixtures from Compositional Analysis, or GPA

Standard 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, Btu/100 scf (all incorporated by reference under §75.6).

106 = Conversion of BTU to MMBTU

B. Compliance with the fuel heat input percentage requirements of Condition 3 – Table 1.a.6.iv.B shall be

demonstrated by calculating, recording, and maintaining records of the following on a monthly, rolling twelve (12)

month, and rolling thirty-six (36) month basis:

1. The heat input contributed by the combustion of No. 2 fuel oil;

cause the unit(s) to meet the definition of an EGU subject to this

subpart;

3. The date on which you became subject to the currently applicable

emission limits; 4. The date upon which you will

commence or recommence

operations that will cause your unit to meet the definition of an

EGU subject to this subpart, consistent with paragraph (f) of

this section. [Reference §63.10000(h)(2) dated 4/6/16]

B. If/when Emission Unit 3 ceases to

operate in a manner that would subject it to requirements under

Subpart 5U to 40 CFR Part 63, the owner or operator shall submit notice

of this fact at least 30 days prior to the date Emission Unit 3 will cease

complying with the applicable Subpart

5U requirements. The notification shall identify:

1. The name of the owner or operator of the EGU(s), the

location of the facility, the EGU(s)

that will cease complying with Subpart 5U, and the date of the

notice; 2. The currently applicable

subcategory under Subpart 5U, and any 40 CFR Part 60, Part 62,







Recordkeeping)


applicable emission limit and work practice standard in Tables 1

through 3 to Subpart 5U, except as

provided under §63.10009. At the time of writing this permit, the only

applicable requirement from these tables is as follows: [Reference §63.9991(a)(1) dated 04/06/16]

If your

EGU is...

You must meet the

following...

1. An

existing EGU

Conduct a tune-up of the EGU burner and combustion

controls at least each 36 calendar months, or each 48

calendar months if neural network combustion

optimization software is

employed, as specified in §63.10021(e).

3. The owner or operator must meet

each applicable operating limit in Table 4 of Subpart 5U to 40 CFR

Part 63. At the time of writing this permit, no applicable requirement

exists. [Reference §63.9991(a)(2) dated 04/06/16]

4. Except as provided under

paragraph (n) of §63.10000, the owner or operator is subject to the

requirements of Subpart 5U for at least 6 months following the last

date Emission Unit 3 met the

2. The heat input contributed by the combustion of natural gas; and

3. The heat input contributed by the combustion of No. 2

fuel oil as a percentage of the overall heat input contributed by the combustion of No. 2 fuel oil and

natural gas. [Reference §63.10042 dated 04/06/16] C. Compliance with the fuel heat input percentage

requirements of Condition 3 – Table 1.a.6.iv.C shall be

demonstrated by calculating, recording, and maintaining records of the heat input contributed by the combustion

of No. 2 fuel oil as a percentage of Emission Unit 3’s maximum or nameplate heat input, whichever is greater.

This shall be calculated on a monthly and rolling 24-month basis. [Reference §63.10042 dated 04/06/16]

D. Compliance with Condition 3 – Table 1.a.6.iv.D.1,

Condition 3 – Table 1.a.6.iv.D.4, Condition 3 – Table 1.a.6.iv.D.5, and Condition 3 – Table 1.a.6.iv.D.6 shall be

demonstrated by maintaining records of: 1. The date Emission Unit 3 commenced operation as a

unit subject to the requirements of Subpart 5U to 40

CFR Part 63; 2. The date Emission Unit 3 ceased operation as a unit

subject to the requirements of Subpart 5U to 40 CFR Part 63;

3. The date chosen by the owner or operator as the date

upon which Emission Unit 3 was no longer subject to the requirements of Subpart 5U to 40 CFR Part 63;

and 4. Records verifying compliance with all applicable

emission limitations, monitoring requirements, and initial compliance demonstration requirements. [Reference §63.9984(d), §63.10000(f), §63.10000(g), §63.10005(a), and §63.10005(f) dated 04/06/16]

or Part 63 subpart and subcategory that will be applicable

after Emission Unit 3 ceases to

comply with Subpart 5U; 3. The date on which Emission Unit 3

became subject to Subpart 5U; and

4. The date upon which Emission

Unit 3 will cease complying with Subpart 5U, consistent with paragraph (g) of §63.10000. [Reference §63.10000(i)(2) dated 4/6/16]

C. If/when Emission Unit 3 begins to

operate in a manner that would subject it to requirements under

Subpart 5U to 40 CFR Part 63, the

owner or operator shall submit all applicable notifications in §63.7(b)

and (c), §63.8(e), (f)(4) and (6), and §63.9 (b) through (h) by the dates

specified. [Reference §63.10030(a) dated 4/6/16]

D. If/when Emission Unit 3 becomes

subject to the requirements of Subpart 5U to 40 CFR Part 63, the

owner or operator shall submit compliance reports on a semiannual

basis according to the requirements in §63.10031(b). The reports shall be

postmarked no later than the first day

of August (for reports covering the period January 1 through June 30 of

the current calendar year) and the







Recordkeeping)


definition of an EGU subject to Subpart 5U. The owner or

operator may opt to remain subject

to the provisions of Subpart 5U beyond 6 months after the last

date Emission Unit 3 met the definition of an EGU subject to

Subpart 5U. [Reference §63.10000(f) dated 04/06/16]

5. Except as provided under

paragraph (n) of §63.10000, if Emission Unit 3 no longer meets

the definition of an EGU subject to Subpart 5U the owner or operator

must be in compliance with any

newly applicable standards on the date Emission Unit 3 is no longer

subject to Subpart 5U. (a) The date Emission Unit 3 is no

longer subject to Subpart 5U is a date selected by the

owner or operator that must

be at least 6 months from the date that Emission Unit 3 last

met the definition of an EGU subject to Subpart 5U.

(b) Emission Unit 3 must remain

in compliance with Subpart 5U until the date the owner or

operator selects to cease complying with Subpart 5U. [Reference §63.10000(g) dated 04/06/16]

E. Condition 3 – Table 1.a.6.iv.D.3, Condition 3 – Table 1.a.6.iv.D.8, Condition 3 – Table 1.a.6.iv.D.9, and

Condition 3 – Table 1.a.6.iv.D.10 are informational

conditions. In the case that they become applicable, it is required that records corresponding to any newly

applicable requirements described therein are readily available and in a format suitable for review and

comparison to the relevant standard(s), limitation(s), or

monitoring requirement(s). [Reference §63.9991(a)(2), §63.10000(i)(1), §63.10000(j), and §63.10000(k) dated 04/06/16]

F. Compliance with Condition 3 – Table 1.a.6.iv.D.2 and Condition 3 – Table 1.a.6.iv.D.7 shall be demonstrated by

performing, documenting, and maintaining documentation sufficient to verify the completion of the

periodic performance tune-up requirements of Subpart 5U

to 40 CFR Part 63. At the time of writing this permit, the following requirements apply, and the owner or operator

shall maintain records to verify the applicable work has been completed:

1. As applicable, inspect the burner and combustion controls, and clean or replace any components of the

burner or combustion controls as necessary upon

initiation of the work practice program and at least once every required inspection period. Repair of a

burner or combustion control component requiring special order parts may be scheduled as follows:

(a) Burner or combustion control component parts

needing replacement that affect the ability to optimize NOX and CO must be installed within 3

calendar months after the burner inspection, (b) Burner or combustion control component parts

that do not affect the ability to optimize NOX and

first day of February (covering the period July 1 through December 31 of

the previous calendar year). At the

time of writing this permit, the compliance report shall include the

following information: 1. The information required in

§63.10031(c)(1) through (9),

which includes the following at the time of writing this permit:

(a) The information required by the summary report located in

63.10(e)(3)(vi). (b) The total fuel use by each

affected source subject to an

emission limit, for each calendar month within the

semiannual reporting period, including, but not limited to, a

description of the fuel,

whether the fuel has received a non-waste determination by

EPA or your basis for concluding that the fuel is not

a waste, and the total fuel

usage amount with units of measure.

(c) Indicate whether Emission Unit 3 burned new types of

fuel during the reporting period. If Emission Unit 3 did

burn new types of fuel you







Recordkeeping)


6. If/when Emission Unit 3 commences operations that cause

it to meet the definition of an EGU

subject to Subpart 5U, the owner or operator shall become subject to

the provisions of Subpart 5U, including, but not limited to, the

emission limitations and the

monitoring requirements, as of the first day Emission Unit 3 meets the

definition of an EGU subject to Subpart 5U. The owner or operator

must complete all initial compliance demonstrations for Subpart 5U

applicable to Emission Unit 3,

including tune-up requirements, within 180 days after it commences

operations that cause it to meet the definition of an EGU subject to

Subpart 5U. [Reference §63.10000(h)(1) dated 4/6/16, §63.10005(a) dated 4/6/16, and §63.10005(f) dated 04/06/16]

7. For EGUs not employing neural network combustion optimization

during normal operation, each performance tune-up specified in

§63.10021(e) must be no more than 36 calendar months after the

date of the previous performance tune-up. [Reference §63.10006(i)(1) dated 04/06/16] (a) For the first tune-up, the

owner or operator may either

CO may be installed on a schedule determined by the operator;

2. As applicable, inspect the flame pattern and make any

adjustments to the burner or combustion controls necessary to optimize the flame pattern. The

adjustment should be consistent with the manufacturer's specifications, if available, or in

accordance with best combustion engineering practice

for that burner type; 3. As applicable, evaluate windbox pressures and air

proportions, making adjustments and effecting repair to dampers, actuators, controls, and sensors;

4. Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated and functioning

properly. Such inspection may include calibrating

excess O2 probes and/or sensors, adjusting overfire air systems, changing software parameters, and

calibrating associated actuators and dampers to ensure that the systems are operated as designed.

Any component out of calibration, in or near failure, or

in a state that is likely to negate combustion optimization efforts prior to the next tune-up, should

be corrected or repaired as necessary; 5. Optimize combustion to minimize generation of CO

and NOX. This optimization should be consistent with

the manufacturer's specifications, if available, or best combustion engineering practice for the applicable

burner type. NOX optimization includes burners, overfire air controls, concentric firing system

improvements, neural network or combustion efficiency software, control systems calibrations,

adjusting combustion zone temperature profiles, and

must include the date of the performance test where that

fuel was in use.

(d) Include the date of the most recent tune-up for Emission

Unit 3. The date of the tune-up is the date the tune-up

provisions specified in

§63.10021(e)(6) and (7) were completed.

(e) Should you choose to rely on paragraph (2) of the definition

of “startup” in §63.10042 for Emission Unit 3, for each

instance of startup or

shutdown you shall: (i) Include the maximum

clean fuel storage capacity and the maximum hourly

heat input that can be

provided for each clean fuel determined according

to the requirements of §63.10032(f).

(ii) Include the information

required to be monitored, collected, or recorded

according to the requirements of

§63.10020(e). (iii) If you choose to use CEMS

to demonstrate







Recordkeeping)


perform the burner inspection any time prior to the tune-up

or delay the first burner

inspection until the next scheduled EGU outage

provided the requirements of §63.10005 are met.

(b) Subsequently, the owner or

operator must perform an inspection of the burner at

least once every 36 calendar months unless the EGU

employs neural network combustion optimization

during normal operations in

which case the owner or operator must perform an

inspection of the burner and combustion controls at least

once every 48 calendar

months. (c) If the EGU is offline when a

deadline to perform the tune-up passes, the owner or

operator shall perform the

tune-up work practice requirements within 30 days

after the re-start of the affected unit. [Reference §63.10021(e) dated 04/06/16]

8. If/when Emission Unit 3 ceases to

operate in a manner that causes it to meet the definition of an EGU

add-on controls such as SCR and SNCR; CO optimization includes burners, overfire air controls,

concentric firing system improvements, neural

network or combustion efficiency software, control systems calibrations, and adjusting combustion zone

temperature profiles; 6. While operating at full load or the predominantly

operated load, measure the concentration in the

effluent stream of CO and NOX in ppm, by volume, and oxygen in volume percent, before and after the

tune-up adjustments are made (measurements may be either on a dry or wet basis, as long as it is the

same basis before and after the adjustments are made). You may use portable CO, NOX and

O2 monitors for this measurement. EGU's employing

neural network optimization systems need only provide a single pre- and post-tune-up value rather

than continual values before and after each optimization adjustment made by the system;

7. Maintain on-site and submit, if requested by the

Administrator, an annual report containing the information in paragraphs (e)(1) through (e)(9) of

§63.10021 including: (a) The concentrations of CO and NOX in the effluent

stream in ppm by volume, and oxygen in volume

percent, measured before and after an adjustment of the EGU combustion systems;

(b) A description of any corrective actions taken as a part of the combustion adjustment; and

(c) The type(s) and amount(s) of fuel used over the 12 calendar months prior to an adjustment, but

only if the unit was physically and legally capable

compliance with numerical limits, include hourly

average CEMS values and

hourly average flow values during startup periods or

shutdown periods. Use units of milligrams per

cubic meter for PM CEMS

values, micrograms per cubic meter for Hg CEMS

values, and ppmv for HCl, HF, or SO2 CEMS values.

Use units of standard cubic meters per hour on

a wet basis for flow

values. (iv) If you choose to use a

separate sorbent trap measurement system for

startup or shutdown

reporting periods, include hourly average mercury

concentration values in terms of micrograms per

cubic meter.

(v) If you choose to use a PM CPMS, include hourly

average operating parameter values in terms

of the operating limit, as well as the operating







Recordkeeping)


subject to Subpart 5U, the owner/operator shall demonstrate

compliance with any newly

applicable section 112 or 129 standards on the date selected

consistent with paragraphs (g) and (n) of §63.10000. [Reference §63.10000(i)(1) dated 04/06/16]

9. All air pollution control equipment

necessary for compliance with any

newly applicable emissions limits which apply as a result of the

cessation, commencement, or recommencement of operations

that cause Emission Unit 3 to meet

the definition of an EGU subject to Subpart 5U must be installed and

operational as of the date Emission Unit 3 ceases to be or becomes

subject to Subpart 5U. [Reference §63.10000(j) dated 04/06/16]

10. All monitoring systems necessary

for compliance with any newly applicable monitoring requirements

which apply as a result of the cessation or commencement or

recommencement of operations that cause Emission Unit 3 to meet

the definition of an EGU subject to

Subpart 5U must be installed and operational as of the date Emission

Unit 3 ceases to be or becomes subject to Subpart 5U.

of using more than one type of fuel during that period; and

(d) Report the dates of the initial and subsequent

tune-ups in hard copy, as specified in §63.10031(f)(5), through June 30, 2020. On or

after July 1, 2020, report the date of all tune-ups electronically, in accordance with §63.10031(f).

The tune-up report date is the date when tune-

up requirements in paragraphs (e)(6) and (7) of §63.10021 are completed. [Reference: §63.10021(e), dated 07/029/18]

(e) A report is required for each instance in which a

required tune-up is not conducted. [Reference: §63.10021(g), dated 07/029/18]

vi. Monitoring


A. The heat input contributed by the combustion of each fuel as calculated pursuant to Condition 3 – Table

1.a.6.v.A, and summarized in accordance with the requirements of Condition 3 – Table 1.a.6.v.B and

Condition 3 – Table 1.a.6.v.C.

B. When applicable, the dates when Emission Unit commences or ceases operation as a unit subject to the

requirements of Subpart UUUUU to 40 CFR Part 63. C. Any requirements that become applicable once Emission

Unit 3 commences or ceases operation as a unit subject to the requirements of Subpart UUUUU to 40 CFR Part

63.

D. When applicable, the timing of conducting tune-ups required by Subpart UUUUU to 40 CFR Part 63. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

parameter to PM correlation equation.

(f) You must report emergency

bypass information annually from EGUs with LEE status.

(g) A summary of the results of the annual performance tests

and documentation of any

operating limits that were reestablished during the test,

if applicable. If you are conducting stack tests once

every 3 years to maintain LEE status, consistent with

§63.10006(b), the date of

each stack test conducted during the previous 3 years, a

comparison of emission level you achieved in each stack

test conducted during the

previous 3 years to the 50 percent emission limit

threshold required in §63.10005(h)(1)(i), and a

statement as to whether there

have been any operational changes since the last stack

test that could increase emissions.

(h) A certification. (i) If you have a deviation from

any emission limit, work







Recordkeeping)


(a) All calibration and drift checks must be performed as of the

date Emission Unit 3 ceases to

be or becomes subject to Subpart 5U.

(b) The owner or operator must also comply with provisions of

§63.10010, §63.10020, and

§63.10021 of Subpart 5U. (c) Relative accuracy tests must

be performed as of the performance test deadline for

PM CEMS, if applicable. (d) Relative accuracy testing for

other CEMS need not be

repeated if that testing was previously performed

consistent with CAA section 112 monitoring requirements

or monitoring requirements

under Subpart 5U. [Reference §63.10000(k) dated 04/06/16]

vii. Testing None

viii. Quality Assurance/Quality Control None

ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and

3(b)(2) of this permit, the following information shall be recorded and maintained in a manner suitable for review and

comparison to the applicable limit, standard, restriction, or requirement:

A. The heat input contributed by the combustion of No. 2 fuel oil, calculated pursuant to Condition 3 – Table

1.a.6.v.A.1, and summarized on:

1. A monthly basis; 2. A rolling twelve (12) month basis;

3. A rolling twenty-four (24) month basis; and 4. A rolling thirty-six (36) month basis.

B. The heat input contributed by the combustion of natural

gas, calculated pursuant to Condition 3 – Table 1.a.6.v.A.2, and summarized on:

1. A monthly basis; 2. A rolling twelve (12) month basis; and

3. A rolling thirty-six (36) month basis.

C. The heat input contributed by the combustion of No. 2 fuel oil as a percentage of the overall heat input

contributed by the combustion of No. 2 fuel oil and natural gas summarized on:

1. A monthly basis; 2. A rolling twelve (12) month basis; and

3. A rolling thirty-six (36) month basis.

practice standard, or operating limit, you must also submit a

brief description of the

deviation, the duration of the deviation, emissions point

identification, and the cause of the deviation.

2. If there are no deviations from any

emission limitation (emission limit and operating limit) that applies to

you and there are no deviations from the requirements for work

practice standards in Table 3 to this subpart that apply to you, a

statement that there were no

deviations from the emission limitations and work practice

standards during the reporting period. If there were no periods

during which the CMSs, including

continuous emissions monitoring system, and operating parameter

monitoring systems, were out-of-control as specified in §63.8(c)(7),

a statement that there were no

periods during which the CMSs were out-of-control during the

reporting period; and 3. If you have a deviation from any

emission limitation (emission limit and operating limit) or work

practice standard during the







Recordkeeping)


D. The heat input contributed by the combustion of No. 2 fuel oil as a percentage of Emission Unit 3’s maximum or

nameplate heat input, whichever is greater, on:

1. A monthly basis; and 2. A rolling twenty-four (24) month basis.

E. In the event that Emission Unit 3 commences or ceases operation that would subject it to the requirements of

Subpart 5U to 40 CFR Part 63, the information required

by Condition 3 – Table 1.a.6.v.D shall be maintained. This shall include, but is not necessarily limited to:

1. The results of the initial and any subsequent, periodic performance tune-ups pursuant to the requirements of

Condition 3 – Table 1.a.6.v.F; and 2. A copy of each notification and report that was

submitted to comply with Subpart 5U, including all

documentation supporting any Initial Notification or Notification of Compliance Status or semiannual

compliance report submitted, according to the requirements in §63.10(b)(2)(xiv).

F. In the event that Emission Unit 3’s change in operation

triggers subjection to the requirements referenced in Condition 3 – Table 1.a.6.iv.D.3, Condition 3 – Table

1.a.6.iv.D.8, Condition 3- Table 1.a.6.iv.D.9, or Condition 3 – Table 1.a.6.iv.D.10, then the information referenced

in Condition 3 – Table 1.a.6.v.E shall be maintained.

G. In the event that Emission Unit 3 becomes subject to the requirements of Subpart 5U to 40 CFR Part 63, and is

required to conduct initial and subsequent periodic performance tune-ups, the records referenced in

Condition 3 – Table 1.a.6.v.F shall be maintained, as they apply. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

reporting period, the report must contain the information in

§63.10031(d). If there were

periods during which the CMSs, including continuous emissions

monitoring systems and continuous parameter monitoring

systems, were out-of-control, as

specified in §63.8(c)(7), the report must contain the information in

§63.10031(e). [Reference §63.10031(a), §63.10031(c), and Table 8 to Subpart UUUUU of Part 63 dated 4/6/2016]

4. Report the dates of the initial and subsequent tune-ups in hard copy,

as specified in §63.10031(f)(5), through June 30, 2020. On or

after July 1, 2020, report the date

of all tune-ups electronically, in accordance with §63.10031(f).

The tune-up report date is the date when tune-up requirements

in paragraphs (e)(6) and (7) of

this section are completed. [Reference: §63.10021(e), dated 07/029/18]

5. A report is required for each

instance in which a required tune-up is not conducted. [Reference:

§63.10021(g), dated 07/029/18] xi. Certification:







Recordkeeping)


None in addition to that required by Condition 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.1.3.2.3 and 6.2.2 dated 12/11/2000]

b. Emission Units No. 4 & 5 - Two (2) 13.39 MMBTU/hr Natural Gas-Fired Hot Water Boilers

1. Criteria Pollutants

i. Emission Standard None


Combined emissions from Emission Units

4 & 5 shall not exceed the following on a calendar-year basis:

A. 0.07 tons of SO2; B. 11.17 tons of NOX;

C. 9.38 tons of CO; D. 0.85 tons of PM10 (Condensable &

Filterable); and

E. 0.61 tons of VOCs. [Reference 7 DE Admin. Code 1130 Section 6.1.1 dated 12/11/00]


iv. Operational Limitation The boilers shall only combust natural

gas. [Reference: 7 DE Admin Code 1130 Section 6.1.1 dated 12/11/00]

v. Compliance Method A. Compliance with Condition 3 – Table 1.b.1.ii shall be

demonstrated by estimating and recording emissions of the pollutants specified, in tons, on a monthly and

calendar-year basis. Emissions shall be calculated by

taking the product of the volume of fuel combusted during the applicable period and the following emission

factors: 1. 0.6 lbs SO2/MMSCF;

2. 100 lbs NOX/MMSCF; 3. 84 lbs CO/MMSCF;

4. 7.6 lbs PM10/MMSCF; and

5. 5.5 lbs VOCs/MMSCF. [Reference 7 DE Admin. Code 1130 Section 6.1.3 dated 12/11/00]

B. Compliance with Condition 3 – Table 1.b.1.iv shall be demonstrated by monitoring and recording the type and

volume of fuel combusted in Emission Units 4 & 5 on a monthly and calendar-year basis. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring

The owner or operator shall monitor: A. The type and volume of fuel combusted in Emission Units

4 & 5 on a monthly and calendar-year basis; and B. The emissions generated by the combustion of fuel in

Emission Units 4 & 5 on a monthly and calendar-year

basis.

x. Reporting None in addition to that required by

Conditions 2(a), 2(f)(3), 3(b)(1)(ii), and 3(c)(2) of this permit.


Conditions 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.2.1, dated 12/11/00]







Recordkeeping)


vii. Testing



None

ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the owner or operator shall maintain

the following:

A. The type and volume of fuel combusted on a monthly and calendar-year basis. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

B. The monthly and calendar-year emissions shall be

calculated and recorded for each of the following pollutants:

1. SO2;

2. NOX; 3. CO;

4. PM10; and 5. VOCs. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated

12/11/00]

2. Opacity


Emissions of visible air contaminants and/or smoke from Emission Units 4 & 5

shall not possess a shade or appearance

greater than twenty (20%) percent opacity for an aggregate of more than

three (3) minutes in any one (1) hour or more than fifteen (15) minutes in any


Compliance with Condition 3 – Table 1.b.2.i shall be demonstrated by performing, and recording the results of

quarterly, qualitative visible emission observations of the

boiler stacks to determine the presence or absence of any visible emissions.

A. The observation shall be conducted, at minimum, over a continuous five (5) minute period of time.

x. Reporting

None in addition to that required by Conditions 2(a), 2(f)(3), 3(b)(1)(ii), and

3(c)(2) of this permit.

xi. Certification

None in addition to that required by Conditions 3(c)(3) of this permit.







Recordkeeping)


twenty-four (24) hour period. [Reference 7 DE Admin. Code 1114 Section 2.0 dated 11/11/2013]

ii. Emission Limitation None


None


None

B. The boiler(s) shall be operating at the time of the

observation.

C. The observation may be conducted while both boilers are operating, or individually, but both boilers must be

observed.

D. If a boiler does not operate during a given quarter, this shall be documented and no observation shall be

required. E. This procedure does not require that the opacity of the

emissions be determined. F. Since this procedure requires only the determination of

whether a visible emission occurs and does not require

the determination of opacity levels, observer certification according to the procedures of EPA Reference Method 9

(40 CFR 60, Appendix A) is not required. 1. It is necessary that the observer is educated on the

general procedures for determining the presence of

visible emissions. 2. At a minimum, the observer must be trained and

knowledgeable regarding the effects of background contrast, ambient lighting, observer position relative to

lighting, wind, and the presence of uncombined water

(condensing water vapor) on the visibility of emissions.

G. If visible emissions are observed: 1. The owner or operator shall take corrective action(s)

to eliminate the cause of the opacity and repeat the qualitative observation to determine if the actions

were effective.

2. If corrective action does not eliminate the excess opacity observed during the qualitative visible

emission observation, the boiler shall be shut down

[Reference: 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.2.1, dated 12/11/00]







Recordkeeping)


until the cause of the opacity has been determined and corrected.

H. If no visible emissions are observed, no further action is required. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring

The owner or operator shall monitor the boiler stack for visible emissions pursuant to the requirements of Condition 3

– Table 1.b.v.


this permit.

viii.Quality Assurance/Quality Control

None.

ix. Recordkeeping


records of the results of the quarterly visible emission observations, to include:

A. The date(s) of the observation(s); B. The start and stop time(s) of the observation(s);

C. The name and job title of the individual(s) conducting the

observation(s); D. Whether visible emissions were observed during the

observation(s); and E. If applicable, the corrective actions taken to correct any

observed opacity. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

3. Operation & Maintenance







Recordkeeping)




None.


A. At all times, including periods of startup, shutdown, and malfunction,

the owner or operator shall, to the extent practicable, maintain and

operate the facility including

associated air pollution control equipment in a manner consistent

with good air pollution control practice for minimizing emissions. [Reference 7 DE Admin. Code 1101 Section 3 11/01/2013 and 7 DE Admin. Code 1102 Section 11.6 dated 06/11/2006]

B. All structural and mechanical components of the equipment or

process covered by this Permit shall be maintained in proper operating

condition. [Reference 7 DE Admin. Code 1101 Section 3 dated 11/01/2013 and 7 DE Admin. Code 1102 Section 11.6 dated 06/11/2006]


None.

v. Compliance Method Compliance with Condition 3 – Table 1.b.1.iii.B and

Condition 3 – Table 1.b.1.iii.C shall be based on information available to the Department which may include, but is not

limited to, monitoring results, opacity observations, review of operating and maintenance procedures, work orders for

maintenance and repairs performed, and inspection of the

source. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring The owner or operator shall monitor the status of

maintenance and operation of Emission Units 4 & 5. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing



None.

ix. Recordkeeping

x. In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the owner or operator shall maintain:

A. The occurrence and duration of each malfunction of Emission Units 4 & 5.

B. Actions taken during periods of malfunction to minimize

emissions, including corrective actions to restore Emission Units 4 & 5 to their normal or usual manner of operation.

C. Planned and unplanned maintenance or repairs performed on Emission Units 4 & 5 which may have an

xi. Reporting None in addition to that required by


xii. Certification

None in addition to that required by








Recordkeeping)


impact on the formation and emission of air pollution. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

c. Emission Units No. 6 & 7 - Two (2) Cold Solvent Cleaners

1. Standards


None


None

iii. Operational Standard A. The vapor pressure of VOC-containing

solvent used in the cold solvent

cleaners shall not exceed 1.0 millimeters of mercury (mmHg)

measured at 20°C (68°F). [Reference 7 DE Admin. Code 1130 Section 6.1.1 and 6.2.1 dated 12/11/00 and 7 DE Admin. Code 1124 Section 33.3.4 dated 11/11/01]

B. The cold solvent cleaners shall be equipped with working mode covers

that are kept closed at all times except when parts or tools are being placed

into or being removed from the

machine. 1. The working mode covers shall be

free of cracks, holes, and other defects; and

2. Shall be easily opened or closed. [Reference 7 DE Admin. Code 1124 Section 33.3.1 dated 11/11/01]

C. The operating requirements for the

cold solvent cleaners shall be

summarized and permanently posted


A. Compliance with the operational standard established by Condition 3 – Table 1.c.iii.A shall be demonstrated by

maintaining the invoice, bill of sale, certificate that

corresponds to a number of sales, Safety Data Sheet (SDS), or other appropriate documentation acceptable to

the Department for any solvent(s) used in the cold cleaning machines. Such certification shall indicate:

1. The name and address of the solvent supplier;

2. The type of solvent including the product or vendor identification number; and

3. The vapor pressure of the solvent measured in mmHg at 20°C (68°F). [Reference 7 DE Admin. Code 1124 Sections 33.3.5 and 33.3.6 dated 11/11/01]

B. Compliance with the remaining operational standards

established by Condition 3 – Table 1.c.iii.B through

Condition 3 – Table 1.c.iii.M shall be determined: 1. Using information available to the Department which

may include, but is not limited to, monitoring results, review of operating and maintenance procedures,

work orders for maintenance and repairs performed, and inspection of the source; and

2. By conducting and maintaining records of employee

training covering the requirements of Condition 3 – Table 1.c.iii.B through Condition 3 – Table 1.c.iii.M at

least once each calendar year. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring

x. Reporting

In addition to that required by Conditions 2(a), 2(f)(3), 3(b)(1)(ii), and 3(c)(2) of

this permit, the owner or operator shall

report the following information to the Department within thirty (30) calendar

days of becoming aware of any excess emissions from the cold solvent cleaners: [Reference 7 DE Admin. Code 1124 Section 5.2 dated 01/11/93] A. The name and location of the facility. B. The subject source(s) that caused the

excess emissions.

C. The time and date of the first observation of the excess emissions.

D. The cause and expected duration of the excess emissions.

E. The estimated rate of emissions

(expressed in the units of the emission limitation) and the operating

data and calculations used in determining the magnitude of the

excess emissions. F. The proposed corrective action(s) and

schedule to correct the conditions

causing the excess emissions.

xi. Certification







Recordkeeping)


on or near the cold solvent cleaners in a manner that is legible and

conspicuous. [Reference 7 DE Admin. Code 1124 Section 33.3.2.1 dated 11/11/01]

D. The cold solvent cleaners shall be

equipped with downtime mode covers that are kept closed at all times except

when parts or tools are being placed into or being removed from the

machine.

1. The downtime mode covers shall be free of cracks, holes, and other

defects; and 2. Shall be readily opened or closed.

[Reference 7 DE Admin. Code 1124 Section 33.3.2.2 dated 11/11/01]

E. The solvent in the cold solvent cleaners shall not be heated. [Reference 7 DE Admin. Code 1130 Section 6.1.1 and 6.2.1 dated 12/11/00]

F. Waste solvent, still bottoms, and sump

bottoms shall be collected and stored in closed containers. The closed

containers may contain a device that allows pressure relief, but does not

allow liquid solvent to drain from the

container. [Reference 7 DE Admin. Code 1124 Section 33.3.3.1 dated 11/11/01]

G. Cleaned parts shall be drained at least 15 seconds or until dripping ceases,

whichever is longer. 1. Parts having cavities or blind holes

shall be tipped or rotated while the part is draining.

The owner or operator shall monitor the following: A. The vapor pressure of the solvent used in the cold solvent

cleaners.

B. The frequency of training employees on the cold-solvent cleaner-related requirements within this permit.

C. Employee adherence to the operational standards. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]


this permit.


None.

ix. Recordkeeping In addition to the requirements of Conditions 3(b)(1)(ii) and

3(b)(2) of this permit, the owner or operator shall maintain:

A. The certifications specified in Condition 3 – Table 1.c.1.v.A.

B. Records of employee training in accordance with the requirements of Condition 3 – Table 1.c.1.v.B.2. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

None in addition to that required by Conditions 3(c)(3) of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.2.1, dated 12/11/00]







Recordkeeping)


2. During the draining, tipping or rotating, the parts shall be

positioned so that solvent drains

directly back to the cleaning machine. [Reference 7 DE Admin. Code 1124 Section 33.3.3.2 dated 11/11/01]

H. Flushing of parts using a flexible hose

or other flushing device shall be performed only within the freeboard

area of the cold cleaning machine.

The solvent flushing shall be a solid fluid stream, not an atomized or

shower spray, at a pressure that does not exceed 10 pounds per square inch

gauge (psig). [Reference 7 DE Admin. Code 1124 Section 33.3.3.3 dated 11/11/01]

I. Work area fans shall be located and

positioned so that they do not blow across the opening of the cold

cleaning machine. [Reference 7 DE Admin. Code 1124 Section 33.3.3.4 dated 11/11/01]

J. Sponges, fabric, wood, leather, paper

products, and other absorbent materials shall not be cleaned or dried

in the cold cleaning machine. [Reference 7 DE Admin. Code 1124 Section 33.3.3.5 dated 11/11/01]

K. Any solvent bath agitator shall be operated to produce a rolling motion

of the solvent with no observable splashing of the solvent against the

tank walls or the parts being cleaned. Air agitated solvent baths may not be







Recordkeeping)


used. [Reference 7 DE Admin. Code 1124 Section 33.3.3.6 dated 11/11/01]

L. Spills during solvent transfer and use of the cold cleaning machine shall be

cleaned up immediately, and the wipe

rags or other absorbent material shall be immediately stored in covered

containers for disposal or recycling. [Reference 7 DE Admin. Code 1124 Section 33.3.3.7 dated 11/11/01]

M. The owner or operator shall ensure

that the solvent level does not exceed

the fill line. [Reference 7 DE Admin. Code 1124 Section 33.3.3.8 dated 11/11/01]


None

d. Emission Unit No. 8 - 2,704,800 Gallon No. 2 Fuel Oil Storage Tank

1. Standards


None.

ii. Emission Limitation None.



Emission Unit 8 shall only store No. 2 fuel oil or any other liquid with a true vapor

pressure less than 0.5 pounds per square


Compliance with the operational limitation established by Condition 3 – Table 1.d.1.iv shall be demonstrated by

maintaining documentation of the true vapor pressure of the fuel oil, or other liquid, stored in the storage tank. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring

The owner or operator shall monitor the following: A. The true vapor pressure of the fuel oil, or other liquid,

stored in the storage tank. B. For each shipment of volatile organic liquid (VOL) that is

transferred to the storage tank and does not consist

solely of No. 2 fuel oil, the owner or operator shall

x. Reporting



xi. Certification








Recordkeeping)


inch. Reference 7 DE Admin. Code 1130 Sections 6.1.1 and 6.2.1 dated 12/11/00]

monitor the type, vapor pressure, and volume of liquid that is transferred to the storage tank. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]


this permit.

viii. Quality Assurance/Quality Control None.


3(b)(2) of this permit, the owner or operator shall maintain: A. The true vapor pressure of the fuel oil, or other liquid,

stored in the storage tank.

B. For each shipment of volatile organic liquid (VOL) that is transferred to the storage tank and does not consist

solely of No. 2 fuel oil, records of the type, vapor pressure, and volume of liquid that is transferred to the

storage tank. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

C. Records showing the dimensions of the storage vessel

and an analysis showing the capacity of the storage vessel for the life of the storage tank. [Reference 7 DE Admin. Code 1149 Section 49.5.2 dated 11/29/94]

e. Facility Wide

1. Disposal, Handling, and Storage of Volatile Organic Compounds (VOCs)

i. Emission Standard The owner or operator shall not cause,

allow, or permit the disposal of more

than eleven (11) pounds of any VOC, or

v. Compliance Methodology Compliance with the emission standard and operational

limitations specified in Condition 3 – Table 1.e.1.i and


Conditions 2(a), 2(f)(3), 3(b)(1)(ii), and








Recordkeeping)


of any materials containing more than eleven (11) pounds of any VOCs, at this

facility in any one (1) day in a manner that would permit evaporation of VOC

into the ambient air. [Reference 7 DE Admin. Code 1124 Section 8.4.1 dated 03/11/11]



None


A. The requirements of Condition 3 – Table 1.e.1.i include, but are not

limited to, the disposal of VOCs from VOC control devices. [Reference 7 DE Admin. Code 1124 Section 8.4.2 dated 03/11/11]

B. The requirements of Condition 3 – Table 1.e.1.i do not apply to:

1. Any VOC or material containing

VOC emitted from the facility that is subject to a VOC standard under

7 DE Admin. Code 1124. [Reference 7 DE Admin. Code 1124 Section 8.4.1.1 dated 03/11/11]

2. Coating sources that are exempt

from the emission limitations of

10.0 through 23.0 of 7 DE Admin. Code 1124. [Reference 7 DE Admin. Code 1124 Section 8.4.1.2 dated 03/11/11]

Condition 3 – Table.1.e.1.iv.A through Condition 3 – Table 1.e.1.iv.I shall be determined:

A. Using information available to the Department which may include, but is not limited to, monitoring results, review of

operating and maintenance procedures, work orders for maintenance and repairs performed, and inspection of

the source; and

B. By conducting and maintaining records of employee training covering the requirements of Condition 3 – Table

1.e.1.i and Condition 3 – Table.1.e.1.iv.A through Condition 3 – Table 1.e.1.iv.I at least once each calendar

year. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring The owner or operator shall monitor the:

A. Disposal, handling, and storage of VOC-containing products and materials to ensure compliance with the

emission standard and operational limitations specified in

Condition 3 – Table 1.e.1.i and Condition 3 – Table.1.e.1.iv.A through Condition 3 – Table 1.e.1.iv.I;

B. Frequency of training employees on the VOC disposal, handling, and storage requirements within this permit;

and C. Employee adherence to the operational standards.

[Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]


this permit.

viii. Quality Assurance/Quality Control:

xi. Certification








Recordkeeping)


3. Waste paint (sludge) handling systems, water treatment systems,

and other similar operations at coating facilities using complying

coatings. [Reference 7 DE Admin. Code 1124 Section 8.4.1.3 dated 03/11/11]

4. Any VOC or material containing

VOCs used during process maintenance turnarounds for

cleaning purposes, provided that the provisions of Condition 3 –

Table 1.e.1.iv.C, Condition 3 – Table 1.e.1.iv.D, Condition 3 –

Table 1.e.1.iv.E, and Condition 3 –

Table 1.e.1.iv.F are followed. [Reference 7 DE Admin. Code 1124 Section 8.4.1.4 dated 03/11/11]

C. Cloth or paper impregnated with VOCs

shall be stored and disposed of in closed containers. The containers

shall be kept closed at all times, except when adding or removing

material. [Reference 7 DE Admin. Code 1124 Section 8.4.3 dated 03/11/11]

D. Spent and fresh VOC or VOC-

containing material shall be disposed of in closed containers. The containers

shall be kept closed at all times, except when adding or removing

material. [Reference 7 DE Admin. Code 1124 Section 8.4.4 dated 03/11/11]

E. The owner or operator shall not use

VOCs for the cleanup of spray

None.


3(b)(2) of this permit, the owner or operator shall maintain records of employee training in accordance with the

requirements of Condition 3 – Table 1.e.1.v.B. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]







Recordkeeping)


equipment unless the equipment is used to collect the cleaning

compounds and to minimize the VOC evaporation to the atmosphere in

accordance with Sections 8.4.5.1 through 8.4.5.5 of 7 DE Admin.

Code 1124. [Reference 7 DE Admin. Code 1124 Section 8.4.5 dated 03/11/11]

F. The owner or operator of a facility

subject to 8.4 of 7 DE Admin. Code 1124 shall:

1. Convey VOC-containing cleaning materials from one location to

another in closed containers or

pipes. 2. Handle and transfer all fresh and

spent cleaning solvent and other VOC-containing material to or from

any container, tank, vat, vessel,

mixing vessel, or piping system, etc. in such a manner that

minimizes spills and other losses. 3. Clean up spills of fresh and spent

cleaning solvent and other VOC-containing material immediately. [Reference 7 DE Admin. Code 1124 Section 8.4.6 dated 03/11/11]

G. The owner or operator of a facility

subject to 8.4 of 7 DE Admin. Code 1124 shall minimize air circulation

around cleaning operations and shall implement equipment practices that

minimize emissions including keeping







Recordkeeping)


part cleaners covered when not in use, and maintaining cleaning

equipment to repair solvent leaks. [Reference 7 DE Admin. Code 1124 Section 8.4.7 dated 03/11/11]

H. The owner or operator shall not build,

erect, install, or use any article, machine, equipment, process, or other

method the use of which conceals

emissions that would otherwise constitute non-compliance with the

requirements of this permit. This includes, but is not limited to:

1. The use of gaseous diluents to achieve compliance; and

2. The piecemeal carrying out of an

operation to avoid coverage by a Section of 7 DE Admin. Code

1124 that applies only to operations larger than a specified

size. [Reference 7 DE Admin. Code 1124 Sections 7.1 and 7.2 dated 01/11/93]

I. The owner or operator of a facility

subject to this 7 DE Admin. Code 1124 shall not discharge or dispose of

VOCs or material containing VOCs to surface impoundments, pits,

wastewater treatment facilities or

sewers for the purpose of circumventing any provision or

requirement of 7 DE Admin. Code 1124. [Reference 7 DE Admin. Code 1124 Section 7.3 dated 01/11/93]







Recordkeeping)


2. Visible Emissions


Visible emissions of air contaminants shall not exceed twenty (20) percent

opacity for an aggregate of more than

three (3) minutes in any one (1) hour period or more than fifteen (15) minutes

in any twenty-four (24) our period. [Reference 7 DE Admin. Code 1114 Section 2.0 dated 11/11/13]




None


Compliance with the emission standard of Condition 3 – Table 1.e.2.i shall be demonstrated by:

A. Conducting the opacity monitoring required under the

sections of the permit related to Emission Units 3, 4, & 5; B. Conducting informal opacity observations as part of daily

operations; and C. Taking corrective action if standard-exceeding opacity is

observed from any of the permitted equipment. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vi. Monitoring The owner or operator shall monitor the opacity of exhaust

gas from all permitted equipment according to the applicable requirements and take corrective action as necessary. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing

None in addition to that required by Condition 3(b)(1)(ii) of

this permit.



3(b)(2) of this permit, the owner or shall maintain records of: A. Any instance where permitted equipment’s emissions

exceeded the emission standard specified in Condition 3 – Table 1.e.2.i; and

x. Reporting



xi. Certification








Recordkeeping)


B. The corrective actions taken to address the opacity. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

3. Operations/Maintenance


ii. Emission Limitation None.


A. At all times, including periods of

startup, shutdown, and malfunction, the owner or operator shall, to the

extent practicable, maintain and operate the facility including

associated air pollution control equipment in a manner consistent

with good air pollution control practice

for minimizing emissions.

B. All structural and mechanical

components of the equipment or process covered by this Permit shall

be maintained in proper operating

condition. [Reference 7 DE Admin. Code 1101 Section 3 dated 11/01/2013 and 7 DE Admin. Code 1102 Section 11.6 dated 06/11/2006]


None

v. Compliance Methodology Compliance with Condition 3 – Table 1.e.3.iii.A and Condition

3 – Table 1.e.3.iii.B shall be based on information available to

the Department which may include, but is not limited to, monitoring results, opacity observations, review of operating

and maintenance procedures, review of work orders for maintenance and repairs performed, and inspection of the

source. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring The owner or operator shall monitor the status of

maintenance and operation of the equipment covered by this permit. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing


viii. Quality Assurance/Quality Control:

None.

ix. Recordkeeping

In addition to the requirements of Conditions 3(b)(1)(ii) and 3(b)(2) of this permit, the owner or shall maintain records of:

A. The occurrence and duration of each malfunction of permitted equipment, or any associated air pollution

control and monitoring equipment.


Conditions 2(a), 2(f)(3), 3(b)(1)(ii), and










Recordkeeping)


B. Actions taken during periods of malfunction to minimize emissions, including corrective actions to restore

malfunctioning process, air pollution control, or

monitoring equipment to its normal or usual manner of operation.

C. Planned and unplanned maintenance or repairs performed on permitted equipment, specifically those

which may have an impact on the formation and emission

of air pollution. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

4. Architectural and Industrial Maintenance Coatings

i. Emission Standard A. On or after the compliance date set in

Table 1-1 of 7 DE Admin. Code 1141, no person shall apply or solicit

the application of an architectural coating with a VOC content in excess

of the limits provided in Table 1-1. [Reference: 7 DE Admin. Code 1141 Section 1.3.1, dated 12/11/16]

B. The standard set by Condition 3 – Table 1.e.4.i.A does not apply to:

1. Any aerosol coating product; or 2. Any architectural coating that is

sold in a container with a volume of one liter (1.057 quarts) or less. [Reference: 7 DE Admin. Code 1141 Sections 1.1.3.2 and 1.1.3.3, dated 12/11/16]


None.


v. Compliance Methodology Compliance with the emission and operational standards

established by Condition 3 – Table 1.e.4.i and Condition 3 – Table 1.e.4.iii, respectively shall be demonstrated by

recording and maintaining the following information for each application of coating at the facility:

A. The coating category of the coating applied, as defined in

Section 1.2 of 7 DE Admin. Code 1141 and summarized in Table 1-1 of 7 DE Admin. Code 1141.

B. The volume of coating applied. C. The VOC content of the coating applied, based on the

manufacturer-provided label or product-specific Safety

Data Sheet (SDS). D. The corresponding VOC content limit for that specific

coating as outlined in Table 1-1 of 7 DE Admin. Code 1141.

E. The percentage of thinner applied to the coating.

vi. Monitoring




xi. Certification









Recordkeeping)


A. The owner or operator shall not apply, or allow the application of,

architectural coatings with a VOC

content greater than those specified in Table 1-1 of 7 DE Admin. Code

1141. [Reference: 7 DE Admin. Code 1141 Sections 6.1.3.1.2 and 6.2.1, dated 12/11/00]

B. All architectural coating containers used to apply the contents therein to

a surface directly from the container

by pouring, siphoning, brushing, rolling, padding, ragging, or other

means, shall be closed when not in use.

1. These architectural coating

containers include, but are not limited to, drums, buckets, cans,

pails, trays, or other application containers.

2. Containers of any VOC-containing materials used for thinning or

cleanup shall also be closed when

not in use. [Reference: 7 DE Admin. Code 1141 Section 1.3.4, dated 12/11/16]

C. No person shall apply or solicit the application of any architectural coating

that is thinned to exceed the applicable VOC limit specified in Table

1-1 of 7 DE Admin. Code 1141. [Reference: 7 DE Admin. Code 1141 Section 1.3.5, dated 12/11/16]

D. No person shall apply or solicit the application of any rust preventive

A. The information specified by Condition 3 – Table 1.e.4.v.A to ensure compliance with the relevant standard of 7 DE

Admin. Code 1141.

B. The status of architectural coating containers during periods when they are not in use to ensure they are kept

closed pursuant to Condition 3 – Table 1.3.4.iii.B. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing In addition to that required by Condition 3(b)(1)(ii) of this

permit, the owner or operator shall conduct the testing

required by Section 1.6 of 7 DE Admin. Code 1141, when necessary. [Reference: 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.2.1, dated 12/11/00]

viii. Quality Assurance/Quality Control: None.


3(b)(2) of this permit, the owner or operator shall maintain the following information:

A. For each application of coating at the facility:

1. The coating category of the coating applied, as defined in Section 1.2 of 7 DE Admin. Code 1141

and summarized in Table 1-1 of 7 DE Admin. Code 1141.

2. The volume of coating applied. 3. The VOC content of the coating applied, based on the

manufacturer-provided label or product-specific Safety

Data Sheet (SDS).







Recordkeeping)


coating, manufactured before March 1, 2017, for industrial use unless such

rust preventive coating complies with

the industrial maintenance coating VOC limit specified in Table 1-1 of 7

DE Admin. Code 1141. [Reference: 7 DE Admin. Code 1141 Section 1.3.6, dated 12/11/16]

E. For any coating that does not meet

any of the definitions for the specialty coatings categories listed in Table 1-

1 of 7 DE Admin. Code 1141, the

VOC content limit shall be determined by classifying the coating as a flat

coating or a non-flat coating, or a non-flat high-gloss coating based on

its gloss, as defined in subsection 1.2

of 7 DE Admin. Code 1141and the corresponding flat or non-flat, or non-

flat high-gloss coating VOC limit in Table 1-1 of 7 DE Admin. Code 1141

shall apply. [Reference: 7 DE Admin. Code 1141 Section 1.3.7, dated 12/11/16]

F. For products manufactured before

March 1, 2017, notwithstanding the provisions of subsection 1.3.1 of 7 DE

Admin. Code 1141, a person or facility may add up to 10 percent by

volume of VOC to a lacquer to avoid blushing of the finish during days with

relative humidity greater than 70%

and the temperature below 65oF, at the time of application, provided that

4. The corresponding VOC content limit for that specific coating as outlined in Table 1-1 of 7 DE Admin.

Code 1141.

5. The percentage of thinner applied to the coating. B. The results of any testing required pursuant to Section

1.6 of 7 DE Admin. Code 1141. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]







Recordkeeping)


the coating contains acetone and no more than 550 grams of VOC per liter

of coating, less water and exempt

compounds, prior to the addition of VOC. [Reference: 7 DE Admin. Code 1141 Section 1.3.8, dated 12/11/16]

iv. Operational Limitation None.

5. Odors (State Enforceable Only)


Odors from the equipment or operations at the McKee Run Generating Station

shall not be detectable beyond the plant property line in sufficient quantities such

as to cause a condition of air pollution. [Reference 7 DE Admin. Code 1119 Section 2.0 dated 02/01/81]


None.



None.


Compliance with Condition 3 – Table 1.e.5.i shall be based on information available to the Department which may

include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance

procedures, review of work orders for maintenance and repairs performed, and inspection of the source. [Reference: 7 DE Admin Code 1130 Section 6.1.3, dated 12/11/00]

vi. Monitoring

The owner or operator shall conduct informal odor observations as part of daily operations, and take corrective

action if/when events occurring at the plant are creating detectable odor in sufficient quantities as to cause a

condition of air pollution beyond the plant property line. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing



x. Reporting











Recordkeeping)


None.

ix. Recordkeeping


records of: A. Any instance where facility operations created odorous

conditions beyond the plant property line; and

B. The corrective actions taken to address the odors. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]

6. 40 CFR Part 63 Subpart ZZZZ (4Z) – Emergency Spark Ignition (SI) Fire Pump Engine



None.


None.

iv. Operational Limitation The owner or operator of the emergency

SI fire pump engine shall comply with all

applicable operating limitations established by Subpart 4Z to 40 CFR Part

63. At the time of writing this permit the following requirements were deemed

applicable: A. Change oil and filter every 500 hours

of operation or annually, whichever

comes first. [Reference: §63.6603(a), dated 01/30/13 and Table 2d(5)(a) of Subpart ZZZZ to 40 CFR Part 63, dated 01/30/13]

v. Compliance Method A. Compliance with the operational limitations established

by Condition 3 – Table 1.e.6.iv.A, Condition 3 – Table 1.e.6.iv.B, and Condition 3 – Table 1.e.6.iv.C shall be

demonstrated by recording and maintaining the following information:

1. A log of the hours of fire pump engine operation on a

daily basis. 2. The hours of fire pump engine operation on a

monthly and rolling twelve (12) month basis. 3. A work order, or equivalent documentation, which

includes the date and description of each:

(a) Oil and filter change. (b) Spark plug inspection, and, when applicable,

replacement. (c) Inspection, and when applicable, replacement, of

associated hoses and belts. B. Compliance with the operational limitations of Condition

3 – Table 1.e.6.iv.D through Condition 3 – Table

1.e.6.iv.F shall be based upon available information which may include, but is not limited to, monitoring

results, review of operation and maintenance



xi. Certification









Recordkeeping)


B. Inspect spark plugs every 1,000 hours of operation or annually, whichever

comes first, and replace as necessary. [Reference: §63.6603(a), dated 01/30/13 and Table 2d(5)(b) of Subpart ZZZZ to 40 CFR Part 63, dated 01/30/13]

C. Inspect all hoses and belts every 500

hours of operation or annually, whichever comes first, and replace as

necessary. [Reference: §63.6603(a), dated 01/30/13 and Table 2d(5)(c) of Subpart ZZZZ to 40 CFR Part 63, dated 01/30/13]

D. Install and operate a non-resettable

hour meter. [Reference: §63.6625(f), dated 01/30/13]

E. Minimize the engine's time spent at

idle during startup and minimize the engine's startup time to a period

needed for appropriate and safe loading of the engine, not to exceed

30 minutes, after which time the non-startup emission limitations apply. [Reference: §63.6625(h), dated 01/30/13]

F. At all times the owner or operator must operate and maintain the fire

pump engine, including associated air pollution control equipment and

monitoring equipment, in a manner consistent with safety and good air

pollution control practices for

minimizing emissions. The general duty to minimize emissions does not

require you to make any further efforts to reduce emissions if levels

procedures, review of operation and maintenance records, and inspection of the source.

C. Compliance with the operational limitation of Condition 3

– Table 1.e.6.iv.G shall be determined by recording and maintaining copies of:

1. The manufacturer's emission-related operation and maintenance instructions; or

2. The maintenance plan which was developed for the

maintenance and operation of the engine in a manner consistent with good air pollution control practice for

minimizing emissions. 3. Operating and maintenance activities taken in

accordance with either the manufacturer’s emission-relation operation and maintenance instructions or

the maintenance plan developed by the owner or

operator for the maintenance and operation of the engine in a manner consistent with good air pollution

control practice for minimizing emissions. D. In the event that the owner or operator opts to utilize an

oil analysis program in order to extend the specified oil

change requirement from Condition 3 – Table 1.e.6.iv.A, the following information shall be recorded and

maintained in order to demonstrate the compliance status:

1. A log of the hours of fire pump engine operation on a

daily basis. 2. The hours of fire pump engine operation on a

monthly and rolling twelve (12) month basis. 3. The results of each oil analysis conducted to include:

(a) The date of the oil sample collection; (b) The date of the oil sample analysis;







Recordkeeping)


required by this standard have been achieved. [Reference: §63.6605(b), dated 01/30/13]

G. The owner or operator shall either:

1. Operate and maintain the fire

pump engine according to the manufacturer's emission-related

operation and maintenance instructions; or

2. Develop and follow your own

maintenance plan which must provide to the extent practicable

for the maintenance and operation of the engine in a manner

consistent with good air pollution

control practice for minimizing emissions. [Reference: Table 6(9)(a)(i) and (ii) of Subpart ZZZZ to 40 CFR Part 63, dated 01/30/13]

H. The owner or operator has the option of utilizing an oil analysis program in

order to extend the specified oil change requirement from Condition 3

– Table 1.e.6.iv.A.

1. The oil analysis must be performed at the same frequency specified for

changing the oil in Condition 3 – Table 1.e.6.iv.A.

2. The analysis program must at a minimum analyze the following

three parameters:

(a) Total Acid Number; (b) Viscosity; and

(c) The results of the analysis, to include, at minimum:

(i) The Total Acid Number;

(ii) The Viscosity; and (iii) The percent water content.

(d) A comparison of the oil sample test results to the “condemning limits” specified in Condition 3 –

Table 1.e.6.iv.H.3.

4. A work order, or equivalent documentation, which includes the date and description of corrective actions

taken in the event that the fuel oil sample exceeds any of the specified “condemning limits”.

5. A maintenance plan which includes the analysis program details.

vi. Monitoring The owner or operator shall monitor the following:

A. The hours of fire pump engine on a daily, monthly, and rolling twelve (12) month basis.

B. Scheduling of the maintenance required by Condition 3 –

Table 1.e.6.iv.A through Condition 3 – Table 1.e.6.iv.C. C. Compliance with either the manufacturer-provided

operation and maintenance instructions or the owner/operator-developed operation and maintenance

plan.

D. If the owner or operator opts to conduct the oil analysis program:

1. The scheduling of oil sampling; 2. The results of the corresponding oil sample test

results; 3. Comparison of the test results against the

“condemning limits” of the specified parameters; and







Recordkeeping)


(c) Percent water content. 3. The condemning limits for these

parameters are as follows:

(a) Total Acid Number increases by more than 3.0 milligrams of

potassium hydroxide (KOH) per gram from Total Acid Number

of the oil when new;

(b) Viscosity of the oil has changed by more than 20 percent from

the viscosity of the oil when new; or

(c) Percent water content (by volume) is greater than 0.5.

4. If all of these condemning limits

are not exceeded, the engine owner or operator is not required

to change the oil. 5. If any of the limits are exceeded,

the engine owner or operator must

change the oil within 2 business days of receiving the results of the

analysis. 6. If the engine is not in operation

when the results of the analysis

are received, the engine owner or operator must change the oil

within 2 business days or before commencing operation, whichever

is later. 7. The owner or operator must keep

records of the parameters that are

4. When applicable, the corrective actions taken in the event that the fuel oil sample exceeds any of the

specified “condemning limits”. [Reference 7 DE Admin. Code 1130 Section 6.1.3.1.2 and 6.3.1 dated 12/11/00]

vii. Testing In addition to that required by Condition 3(b)(1)(ii) of this

permit, the owner or operator may perform the testing described in Condition 3 – Table 1.e.6.iv.H as an alternative

to changing the oil used in the fire pump engine at the rate

specified in Condition 3 – Table 1.e.6.iv.A.



3(b)(2) of this permit, the owner or operator shall maintain: A. A log documenting the hours of fire pump engine

operation on a daily basis. B. Records of the hours of fire pump engine operation on a

monthly and rolling twelve (12) month basis.

C. Work orders, or equivalent documentation, which show the date and description of the following maintenance

practices required by Subpart ZZZZ: 1. Oil and filter change.

2. Spark plug inspection, and, when applicable,

replacement. 3. Inspection, and when applicable, replacement, of

associated hoses and belts. D. A copy of either:

1. The manufacturer's emission-related operation and maintenance instructions; or







Recordkeeping)


analyzed as part of the program, the results of the analysis, and the

oil changes for the engine.

8. The analysis program must be part of the maintenance plan for the

engine. [Reference: §63.6625(j), dated 01/30/13]

2. The maintenance plan which was developed for the maintenance and operation of the engine in a manner

consistent with good air pollution control practice for

minimizing emissions. E. Records of the operating and maintenance activities

taken in accordance with either the manufacturer’s emission-relation operation & maintenance instructions

or the maintenance plan developed by the owner or

operator for the maintenance and operation of the engine in a manner consistent with good air pollution

control practice for minimizing emissions. F. In the event that the owner or operator utilizes an oil

analysis program in order to extend the specified oil change requirement from Condition 3 – Table 1.e.6.iv.A,

the following information:

1. The results of each oil analysis conducted to include: (a) The date of the oil sample collection;

(b) The date of the oil sample analysis; (c) The results of the analysis, to include, at

minimum:

(i) The Total Acid Number; (ii) The Viscosity; and

(iii) The percent water content. (d) A comparison of the oil sample test results to the

“condemning limits” specified in Condition 3 –

Table 1.e.6.iv.H.3. 2. Work orders, or equivalent documentation, which

include the date and description of corrective actions taken in the event that the fuel oil sample exceeds

any of the specified “condemning limits”. 3. A maintenance plan which includes the analysis

program details. [Reference 7 DE Admin. Code 1130 Section 6.1.3.2 dated 12/11/00]







Recordkeeping)


f. 7 DE Admin. Code 1136-Acid Rain Program (Emission Unit 3)

1. Acid Rain Program

The Acid Rain Permit is included as a complete and separable part of this operating permit as an enclosure: Permit: AQM-001/00002-IV (Renewal 3).

Permit: AQM-001/00002-IV (Renewal 3) contains the following elements in a format prescribed by the Administrator:

A. All elements for a complete Acid Rain Permit application under §72.31 of 40 CFR Part 72 and 7 DE Admin. Code 1136; B. The applicable Acid Rain emission limitation for sulfur dioxide; and

C. The applicable Acid Rain emission limitation for nitrogen oxides.

D. The Company shall maintain allowances as required by 40 CFR Parts 72, 73, and 76.

Each Acid Rain Permit is deemed to incorporate the definitions of terms under §72.2 of 40 CFR Part 72.



Page 72

Condition 4- Operational Flexibility

a. In addition to the operational flexibility specifically provided in the terms and conditions detailed in

Condition 3 – Table 1 of this permit, the Owner and/or Operator is authorized to make any changes within the facility which contravenes the terms and conditions of this permit without a permit revision

if the change:

1. Is not a modification or otherwise prohibited under any provision of Title I of the Act or the

State Implementation Plan (SIP); and [Reference: 7 DE Admin. Code 1130 Section 6.8 dated 12/11/00]

2. Does not involve a change in any compliance schedule date; and [Reference: 7 DE Admin. Code 1130 Section 6.8 dated 12/11/00]

3. Does not result in a level of emissions exceeding the emissions allowable under this permit, whether expressed herein as a rate of emissions or in terms of total emissions. [Reference: 7 DE Admin. Code 1130 Section 6.8 dated 12/11/00]

b. Before making a change under the provisions of Condition 4(a) of this permit, the Owner and/or

Operator shall provide advance written notice to the Department and to the EPA in accordance with

Condition 3(c)(2)(iii) of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

c. The Owner and/or Operator shall keep records of any changes made under Condition 4 of this permit

in accordance with Condition 3(b)(2)(iv) of this permit. [Reference: 7 DE Admin. Code 1130 Section 6.8.1 dated 12/11/00]

Condition 5- Compliance Schedule

This permit does not contain a compliance schedule. [Reference: 7 DE Admin. Code 1130 Section 6.3.3 dated 12/11/00]

Condition 6. Permit Shield.

a. Permit Shield: Compliance with the terms and conditions of this permit shall constitute compliance

with 7 Del. C. Ch 60 for the discharge of any air contaminant specifically identified in the permit application as of the day of permit issuance. However, nothing in this permit shield shall in any way

limit or affect the following:

1. The provisions of section 303 (Emergency Orders) of the Act, including the authority of the Administrator under that section; or

2. The liability of an owner or operator of a source for any violation of applicable requirements prior to or at the time of permit issuance; or

3. The applicable requirements of the acid rain program consistent with section 408(a) of the Act;

or 4. The ability of EPA to obtain information from a source pursuant to section 114 of the Act.

[Reference: 7 DE Admin. Code 1130 Sections 6.6.4 dated 12/11/00]

Condition 6 – Table 1


Emission Unit 3

i. Sections 2.1 and 2.2 of 7 DE Admin. Code 1104

ii. Sections 2.2, 2.3, and 2.4 of 7 DE Admin. Code 1108

iii. Section 3.5 of 7 DE Admin. Code 1112

iv. Section 2.1 of 7 DE Admin. Code 1114

Emission Units 4 & 5 i. Sections 2.1 and 2.2 of 7 DE Admin. Code 1104



Page 73

Condition 6 – Table 1


ii. Sections 2.2, 2.3, & 2.4 of 7 DE Admin. Code 1108

Emission Units 6 & 7 i. Sections 5 and 33 of 7 DE Admin. Code 1124

Emission Unit 8 i. Section 49 of 7 DE Admin. Code 1124

Facility Wide

i. Sections 1 through 11 of 7 DE Admin. Code 1103

ii. Section 2 of 7 DE Admin. Code 1114

iii. Sections 7 and 8 of 7 DE Admin. Code 1124

iv. Section 1.0 of 7 DE Admin. Code 1141

b. The permit shield granted in Condition 6 of this permit shall not extend to any changes made

pursuant to Condition 2(m)(3) [Minor Permit Modifications] or Condition 4 [Operational Flexibility] of this permit. [Reference: 7 DE Admin. Code 1130 Sections 6.8.2 dated 12/11/00, 7.5.1.6 dated 12/11/00, and 7.5.2.6 dated 12/11/00]

ADM:JLF:JGM:tmm F:\EngAndCompliance\JGM\2020\JGM20036.doc

pc: Dover (Title V) File



Page 74

Appendix A

Enclosure DESCRIPTION

A AQM-001/00002-IV (Renewal 4) Acid Rain Permit



Page 75

Attachment A- Revision History

Date Number Revision Type Description Pages

Revised

05/01/2003 Renewal 1 Permit Renewal Renewal of permit; updated to reflect

operating conditions and limitations --

06/11/2003 Revision

01AA Administrative Amendment

Correct Typographical errors. 2

05/06/2004 Revision


Added monitoring of fuel flow to determine NOX emissions for Unit 3

28

12/15/2004 Revision

03AA

Administrative

Amendment

Change of plant operator from DFD to

NAES 1

10/09/2005 Revision 01MPM

Minor Permit Modification

Defined the averaging period for the COMs during start-up, shutdown, and

malfunction as six (6) minutes.

3

02/24/2009 Renewal 2 Permit Renewal Renewal of Title V permit issued. --

12/14/2009 Revision


Correct typographical errors and

incorporate NOX emissions rates from stack testing.

11

05/17/2010 Revision


Incorporate changes for removal of

multicyclones in accordance with federally enforceable construction

permits.

11

07/22/2010 Revision


Changes to Division of Air Quality mailing address.

1

04/30/2013 Renewal 3 Permit Renewal Renewal of Title V permit issued. --

Renewal 4 Permit Renewal Renewal of Title V permit issued. --

ADM:JLF:JGM:tmm F:\EngAndCompliance\JGM\2020\JGM20036.doc

pc: Dover (Title V) File

Documents

6/18/2020 - Delaware