STATE OF NEW HAMPSHIRE 

Department of Environmental Services 

Air Resources Division 

Temporary Permit

Permit No: TP-0008 

Date Issued: March 9, 2009 

Date Reissued: August 2, 2010

This certifies that: 

Northeast Utilities 

Public Service of New Hampshire 

780 North Commercial Street 

Manchester, NH 03101 

has been granted a Temporary Permit for a 

Flue Gas Desulphurization System

at the following facility and location: 

Public Service of New Hampshire 

Merrimack Station 

97 River Rd. 

Bow, NH 03304-3314 

Facility ID No: 3301300026 

Application No: FY07-0103 received June 7, 2007 - Temporary Permit TP-0008

 10-0136, received on June 30, 2010 - Request for the reissuance of Temporary Permit

which includes devices that emit air pollutants into the ambient air as set forth in the permit application 

referenced above which was filed with the New Hampshire Department of Environmental Services, Air 

Resources Division (Division) in accordance with RSA 125-C of the New Hampshire Laws. Request for permit 

renewal is due to the Division at least 90 days prior to expiration of this permit and must be accompanied by the 

appropriate permit application forms. 

This permit is valid upon issuance and expires on September 30, 2011. 

__________________________________ 

 

Director, Air Resources Division 
TABLE OF CONTENTS

ABBREVIATIONS............................................................................................................................................... 3

FACILITY SPECIFIC TEMPORARY PERMIT CONDITIONS .................................................................. 5

I. FACILITY DESCRIPTION OF OPERATIONS..................................................................................................... 5

II. PROJECT DESCRIPTION ............................................................................................................................... 5 

III. PERMITTED ACTIVITIES .............................................................................................................................. 6 

IV. SIGNIFICANT ACTIVITIES IDENTIFICATION AND STACK CRITERIA................................................................ 6 

A. Significant Activity Identification........................................................................................................... 6

B. Stack Criteria ......................................................................................................................................... 7

V. POLLUTION CONTROL EQUIPMENT/METHOD IDENTIFICATION .................................................................... 7 

VI. APPLICABLE REQUIREMENTS...................................................................................................................... 8 

A. Operational and Emission Limitations .................................................................................................. 8

B. Initial Compliance Demonstration Requirements................................................................................ 13

C. Monitoring/Testing Requirements........................................................................................................ 15

D. Recordkeeping Requirements............................................................................................................... 18

E. Reporting Requirements....................................................................................................................... 20

VII. ADMINISTRATIVE PERMIT AMENDMENTS ................................................................................................. 21 

VIII. MINOR PERMIT AMENDMENTS ................................................................................................................. 21 

IX. SIGNIFICANT PERMIT AMENDMENTS......................................................................................................... 21 

X. EMISSION-BASED FEE REQUIREMENTS ..................................................................................................... 22 

XI. PERMIT DEVIATION .................................................................................................................................. 24 
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Temporary Permit TP-0008 

ABBREVIATIONS 

AAL Ambient Air Limit 

AEL Alternative Emission Limit 

AP-42 Compilation of Air Pollutant Emission Factors

ARD Air Resources Division 

ASTM American Society for Testing and Materials 

ATS Allowance Tracking System 

BACT Best Available Control Technology 

BHP (or bhp) Brake Horse Power 

BTU British Thermal Units 

CAA Clean Air Act, 42 U.S.C. § 7401, et seq. 

CAM Compliance Assurance Monitoring 

CAS Chemical Abstracts Service 

CEMS Continuous Emission Monitoring System 

CFR Code of Federal Regulations 

CNG Compressed Natural Gas 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

COMS Continuous Opacity Monitoring System 

CTM Conditional Test Method 

DES New Hampshire Department of Environmental Services 

DER Discrete Emission Reduction 

Env-A New Hampshire Code of Administrative Rules – Air Resources Division 

Env-Wm New Hampshire Code of Administrative Rules – Waste Management Division 

ECS Emission Control System 

ERC Emission Reduction Credit 

ETS Emissions Tracking System 

FGD Flue Gas Desulphurization 

gal/hr Gallons per hour 

HAP Hazardous Air Pollutant 

HHV High Heat Value 

HCl Hydrochloric acid 

hr Hour 

kscfm 1,000 standard cubic feet per minute 

kGal 1,000 gallons 

KVDC Kilovolt Direct Current 

KW Kilowatt 

LAER Lowest Achievable Emission Rate 

lb/hr Pounds per hour 

LNB Low NOx Burner 

LNG Liquid Natural Gas 

LPG Liquid Petroleum Gas (Propane) 

MACT Maximum Achievable Control Technology 

mmBtu Million British Thermal Units 

MMCF Million Cubic Feet 

MW Megawatt 
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Temporary Permit TP-0008 

ABBREVIATIONS (cont.)

NAAQS National Ambient Air Quality Standard 

NG Natural Gas 

NHDES (or DES) New Hampshire Department of Environmental Services 

NMOC Non-Methane Organic Compound 

NOx Oxides of Nitrogen 

NSPS New Source Performance Standard 

NSR New Source Review 

PM Particulate Matter 

PM10 Particulate Matter less than 10 microns diameter 

ppm part per million 

ppmdv part per million by dry volume 

PSD Prevention of Significant Deterioration 

PSI Pounds per Square Inch 

PTE Potential to Emit 

RACT Reasonably Available Control Technology 

RTAP Regulated Toxic Air Pollutant 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

TSP Total Suspended Particulate Matter 

TPY Tons per Year 

USEPA United States Environmental Protection Agency

VOC Volatile Organic Compound 
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Facility Specific Temporary Permit Conditions 

I. Facility Description of Operations

Public Service of New Hampshire - Merrimack Station is a fossil fuel-fired electricity generating 

facility, owned and operated by Public Service of New Hampshire (PSNH), a subsidiary of Northeast 

Utilities. The facility is comprised of two utility boilers, two combustion turbines operating as load 

shaving units, an emergency generator, an emergency boiler, and coal handling systems including 

primary and secondary coal crushers, coal piles, coal conveyor systems, and coal unloading from 

railcars. The facility operations also include various activities that are classified as insignificant or 

exempt activities. 

The two utility boilers (MK1 and MK2) primarily burn bituminous coal, the two combustion 

turbines primarily burn No. 1 fuel oil or JP-4, the emergency generator burns No. 2 fuel oil or diesel

fuel, and the emergency boiler burns No. 2 fuel oil or diesel fuel. PSNH – Merrimack Station ignites 

the utility boilers with No. 2 fuel oil. 

Each boiler stack is equipped with continuous emissions monitoring systems (CEMS) and a 

continuous opacity monitoring system (COMS). PSNH – Merrimack Station has installed control 

equipment and implemented operational changes to reduce emissions, including trials of low sulfur 

coals to control sulfur dioxide (SO2) emissions, selective catalytic reduction (SCR) systems to 

control nitrogen oxide (NOx) emissions, and electrostatic precipitators (ESP) to control particulate 

matter (PM) emissions. PSNH has also initiated mercury reduction trials including carbon injection 

and the use of low mercury coals. 

PSNH – Merrimack Station operates a fly ash reinjection system in each of the two Boilers. 

II. Project Description

The Owner has filed a Temporary Permit application requesting to install a wet, limestone-based flue 

gas desulphurization (FGD) system to control mercury emissions from Electric Generating Units 

MK1 and MK2. The FGD system will also provide a co-benefit by removing sulfur dioxide 

emissions. The application was filed in accordance with RSA 125-O:13,I, which requires this 

facility to file an initial permit application by June 8, 2007. This permit establishes limits on 

mercury and sulfur dioxide emissions based on the requirements of RSA 125-O:13 and 40 CFR 

51.308, respectively. This permit also contains applicable monitoring, performance testing, 

recordkeeping and reporting requirements for the purpose of ensuring that the facility can comply 

with the requirements of RSA 125-O:13 and 40 CFR 51.308. 

Once the FGD system is constructed and operational, initial stack testing on MK1 and MK2 will be 

used to (1) determine whether the facility complies with the applicable mercury and sulfur dioxide 

limits; and (2) to establish any necessary operating parameters to ensure that the mercury and sulfur 

dioxide limits will be met on an ongoing basis. Periodic stack testing and/or continuous emission 

monitors will be used to verify that the parameters used to monitor and control mercury and sulfur 

dioxide emissions continue to be valid. 
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The facility currently operates under the application shield provisions of Env-A 609.08, Application 

Shield and in accordance with permits FP-T-0054 (MK1), TP-B-0462 (MK2), PO-B-0034 (CT1), 

PO-B-0035 (CT2), PO-B-1788 (Emergency Generator), TP-B-0490 (Emergency Boiler), PO-B-2416 

(Primary Coal Crusher) and PO-B-2417 (Secondary Coal Crusher), which are currently in the 

process of being streamlined into a Title V Operating Permit. These previously issued permits will 

be referenced as “Previous Permits” throughout this document. This Temporary Permit includes 

new conditions associated with this project, and where necessary, identifies conditions of the 

Previous Permits that will either be modified or superseded as a result of this project. All terms and 

conditions of the Previous Permits not specifically identified in this permit remain in effect 

unchanged. Upon issuance of this permit, the Owner shall comply with all unchanged terms and 

conditions of the Previous Permits and all terms and conditions of this permit. 

III. Permitted Activities

In accordance with all of the applicable requirements identified in this permit, the Owner is 

authorized to operate the devices and or processes identified in Sections IV and V within the terms 

and conditions specified in this Permit. 

IV. Significant Activities Identification and Stack Criteria

A. Significant Activity Identification 

The activities identified in Table 1 below are subject to and regulated by this Permit: 

Table 1 - Significant Activity Identification 

Emission 

Unit 

Number 

Description of 

Emission Unit 

Maximum Gross Heat 

Input Rating 

Maximum Operating Conditions 

MK1 Steam Generating 

Unit 1 

(Installed in 

1960) 

Front wall firing 

Bituminous Coal: 1,238 

MMBtu/hr 

a. Maximum fuel consumption rate of bituminous coal 

shall be limited to 48.5 tons/hr, not to exceed 

425,289 tons during any consecutive 12 month 

period1

. 

b. No. 2 fuel oil consumption shall be limited to 1,656 

gallons per hour, not exceed 14.5 million gallons 

during any consecutive 12 month period2

. 

MK2 Steam Generating 

Unit 2 

(Installed in 

1968) 

Opposed wall 

firing 

Bituminous Coal: 3,473 

MMBtu/hr 

a. Maximum fuel consumption rate of bituminous coal 

shall be limited to 136.2 tons/hr, not to exceed 

1,193,078 tons during any consecutive 12 month 

period3. 

b. No. 2 fuel oil consumption shall be limited to 1,656 

gallons per hour, not exceed 14.5 million gallons 

during any consecutive 12 month period4. 

 

1

 The heating value of bituminous coal is assumed to be 12,750 Btu/lb. The fuel consumption limits may vary based on the actual heat 

content of the fuel burned. 

2

 No. 2 fuel oil is used to ignite individual fires before establishing the main coal fires. The heating value of No. 2 fuel oil is assumed 

to be 140,000 Btu/gal. The fuel consumption limits may vary based on the actual heat content of the fuel burned. 

3

 The heating value of bituminous coal is assumed to be 12,750 Btu/lb. The fuel consumption limits may vary based on the actual heat 

content of the fuel burned. 

4

 No. 2 fuel oil is used to ignite individual fires before establishing the main coal fires. The heating value of No. 2 fuel oil is assumed 

to be 140,000 Btu/gal. The fuel consumption limits may vary based on the actual heat content of the fuel burned. 
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Temporary Permit TP-0008 

Table 1 - Significant Activity Identification 

Emission 

Unit 

Number 

Description of 

Emission Unit 

Maximum Gross Heat 

Input Rating 

Maximum Operating Conditions 

MKLC1 Limestone 

Processing and 

Handling System 

Not Applicable Limestone processing rate of the wet limestone ball mills 

of less than 25 tons per hour5

. 

B. Stack Criteria 

The following devices at the Facility shall have exhaust stacks that discharge vertically, without 

obstruction, and meet the criteria in Table 2: 

Table 2 – Stack Criteria 

Stack 

Number 

Emission 

Unit 

Number 

Emission Unit 

Description 

Minimum Stack 

Height (Feet) Above 

Ground Level 

Maximum Inside 

Stack Diameter 

(Feet) 

STMK2 

(Bypass 

Stack) 

MK1 Steam Generating Unit 

No. 1 

317 14.5 

STMK3 MK1 

and/or 

MK2 with 

MK2-PC7 

Steam Generating Units 

No. 1 and/or No. 2 with 

FGD System 

445 21.5 

1. The Owner may change the stack criteria described in Table 2 with notification to DES 

provided that: 

i. An air quality impact analysis is performed either by the facility or DES (if 

requested by the facility in writing) in accordance with Env-A 606 and the 

“Guidance and Procedure for Performing Air Quality Impact Modeling in New 

Hampshire,” and 

ii. The analysis demonstrates that emissions from the modified stack will continue to 

comply with all applicable emission limitations and ambient air limits. 

2. All air modeling data and analyses shall be kept on file for review by DES upon request. 

V. Pollution Control Equipment/Method Identification

The devices and/or processes identified in Table 3 are considered pollution control equipment for 

each identified emissions unit: 

 

5

 Only one wet ball mill will be operated at a time. The second wet ball mill serves as a backup unit.
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Temporary Permit TP-0008 

Table 3 – Pollution Control Equipment/Method Identification 

Pollution 

Control 

Equipment 

Number 

Description of Equipment/Method Emission Unit 

Number Controlled 

MK1-PC1 Electrostatic Precipitator (ESP) #1 on MK1 MK1 

MK1-PC2 ESP #2 on MK1 MK1 

MK1-PC3 Selective Catalytic Reduction (SCR) deNOx System MK1 

MK2-PC4 ESP #1 on MK2 MK2 

MK2-PC5 ESP #2 on MK2 MK2 

MK2-PC6 SCR deNOx System MK2 

MK2-PC7 Flue Gas Desulphurization (FGD) System MK1 and MK2 

VI. Applicable Requirements

A. Operational and Emission Limitations 

The Owner shall be subject to the operational and emission limitations identified in Table 4 

below. 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

1. Env-A 1403 Devices 

subject to 

RSA 125-I 

and Env-A 

1400 

Devices or processes, subject to RSA 125-I and Env-A 1400, shall 

comply with Env-A 1400 (Regulated Toxic Air Pollutants). 

2. Env-A 1403.01(d) Devices 

subject to 

RSA 125-I 

and Env-A 

1400 

Documentation for the demonstration of compliance shall be retained and 

shall be made available to DES for inspection upon request. 

3. Env-A 1404.01 Devices 

subject to 

RSA 125-I 

and Env-A 

1400 

a. The Owner of a new or modified device or process requiring a permit 

under this chapter shall submit an application for a temporary permit 

in accordance with Env-A 607.03. 

b. Pursuant to RSA 125-I:5,I, the owner shall not operate the device or 

process until a temporary permit is issued. 

4. Env-A 1405.01 Devices 

subject to 

RSA 125-I 

and Env-A 

1400 

The Owner of any device or process that emits an RTAP shall determine 

compliance with the AAL by using one of the methods provided in EnvA 1405. Upon request, the Owner of any device or process that emits an 

RTAP shall provide documentation of compliance with the AAL to DES. 

5. Env-A 1002.04 

Fugitive Dust 

MKLC1 The Owner shall prevent, abate, and control fugitive dust emissions using 

best management practices6. 

 

6

 To comply with this provision, PSNH – Merrimack Station shall use Best Management Practices to manage and minimize fugitive 

dust, as established in the PSNH Merrimack Station Environmental Management System Plan for Fugitive Emissions. 
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Temporary Permit TP-0008 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

6. 40 CFR 51.308(e)(1) MK2 a. Beginning on July 1, 2013, when MK2-PC7 (FGD system) is in 

operation, SO2 emissions shall be controlled to 10 percent of the

uncontrolled SO2 emission rate (90 percent SO2 removal). 

Compliance with this percent reduction shall be determined on a 

calendar month average by comparing the SO2 emission rates as 

measured by CEMS on the inlet and outlet of the FGD system. 

b. The Owner shall submit a report no later than December 31, 2014 that 

includes the calendar month average SO2 emission rates at the inlet 

and outlet of the FGD and the corresponding calendar month average 

emissions reductions during the preceding 12 months of operation, 

excluding the initial startup and commissioning period and any periods 

when the FGD system is not operating. DES will use this data to 

establish the maximum sustainable rate of SO2 emissions reductions 

for MK2. The maximum sustainable rate is the highest rate of 

reductions that can be achieved 100 percent of the time. 

c. DES shall establish the maximum sustainable rate of SO2 emissions 

reductions based on a statistical analysis of the data submitted to DES 

pursuant to paragraph b. above. This established rate shall be 

incorporated as a permit condition for MK2. Under no circumstances 

shall the SO2 removal efficiency for MK2 be less than 90 percent. 

7. 40 CFR 51.308(e)(1) MK2 Beginning on July 1, 2013, the Owner shall not operate MK2 unless 

MK2-PC7 is in operation. 

8. 40 CFR 51.308 

Regional Haze Plan 

MK1 a. Beginning on July 1, 2013, when MK2-PC7 (FGD system) is in 

operation, SO2 emissions shall be controlled to 10 percent of the

uncontrolled SO2 emission rate (90 percent SO2 removal). 

Compliance with this percent reduction shall be determined on a 

calendar month average by comparing the SO2 emission rates as 

measured by CEMS on the inlet and outlet of the FGD system. 

b. The Owner shall submit a report no later than December 31, 2014 that 

includes the calendar month average SO2 emission rates at the inlet 

and outlet of the FGD and the corresponding calendar month average 

emissions reductions during the preceding 12 months of operation, 

excluding the initial startup and commissioning period and any periods 

when the FGD system is not operating. DES will use this data to 

establish the maximum sustainable rate of SO2 emissions reductions 

for MK1. The maximum sustainable rate is the highest rate of 

reductions that can be achieved 100 percent of the time. 

c. DES shall establish the maximum sustainable rate of SO2 emissions 

reductions based on a statistical analysis of the data submitted to DES 

pursuant to paragraph b. above. This established rate shall be 

incorporated as a permit condition for MK1. Under no circumstances 

shall the SO2 removal efficiency for MK1 be less than 90 percent. 

9. 40 CFR 51.308 MK1 Beginning on July 1, 2013, the Owner shall not operate MK1 through 

STMK2 (bypass stack) if MK2-PC7 is capable of stable operation. 

10. 40 CFR 51.308 MK1 Beginning on July 1, 2013, the Owner shall not operate MK1 through 

STMK2 (bypass stack) for more than 840 hours in any consecutive 12-

month period. 
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Temporary Permit TP-0008 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

11. Env-A 1606.01(a)(1) MK1 & MK2 For coal burning devices placed in operation before April 15, 1970, the 

sulfur content of the coal shall not exceed 2.8 pounds per million BTU 

gross heat content at any time. 

12. Env-A 1606.01(a)(2) MK1 & MK2 For coal burning devices placed in operation before April 15, 1970, the 

sulfur content of the coal shall not exceed 2.0 pounds per million BTU 

gross heat content averaged over any consecutive 3-month period. 

13. RSA 125-O:13, II Affected 

Sources as 

defined in 

RSA 125-

O:12 

Beginning on July 1, 2013, total mercury emissions from the affected 

sources shall be at least 80 percent less on an annual basis than the 

baseline mercury input, as defined in RSA 125-O:12, III. 

14. RSA 125-O:13, III MK1 & MK2 Prior to July 1, 2013, the Owner shall test and implement, as practicable,

mercury reduction control technologies or methods to achieve early 

reductions in mercury emissions below the baseline mercury emissions. 

The Owner shall report the results of any testing to DES and shall submit 

a plan for DES approval before commencing implementation. 

15. RSA 125-O:13-V MK1 & MK2 a. Mercury reductions (achieved through the operation of the FGD 

system) greater than 80 percent shall be sustained insofar as the 

proven operational capability of the system, as installed, allows. 

b. DES, in consultation with the Owner, shall determine the maximum 

sustainable rate of mercury emissions reductions and incorporate such 

rate as a permit condition for MK1 and MK2. This requirement in no 

way affects the ability of the Owner to earn over-compliance credits 

consistent with RSA 125-O:16, II. 

16. RSA 125-O:13, VI MK1 & MK2 The purchase of mercury emissions allowances or credits from any 

established emissions allowance or credit program shall not be allowed 

for compliance with the mercury reduction requirements of this permit or 

the requirements of RSA 125:O:13. 

17. RSA 125-O:13, VII MK1 & MK2 If the mercury reduction requirement in Item 13 above is not achieved in 

any year after the July 1, 2013 implementation date, and after full 

operation of the FGD technology, then the Owner may utilize early 

emissions reduction credits or over-compliance credits, or both, to make 

up any shortfall, and thereby be in compliance. 

18. RSA 125-O:13, VIII MK1 & MK2 If the mercury reduction requirement in Item 13 above is not achieved by 

the Owner in any year after the July 1, 2013 implementation date despite 

the Owner's installation and full operation of FGD technology, consistent 

with good operational practice, and the owner's exhaustion of any 

available early emissions reduction or over-compliance credits, then the 

owner shall be deemed in violation of this section unless it submits a plan 

to DES, within 30 days of such noncompliance, and subsequently obtains 

approval of that plan for achieving compliance within one year from the 

date of such noncompliance. DES may impose conditions for approval of 

such plan. 
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Temporary Permit TP-0008 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

19. RSA 125-O:17 MK1 & MK2 Variances from mercury emissions reduction requirements: 

a. The Owner may request a variance from the mercury emissions 

reduction requirements of this permit and RSA 125-O:13, by 

submitting a written request to DES. The request shall provide 

sufficient information concerning the conditions or special 

circumstances on which the variance request is based to demonstrate 

to the satisfaction of DES that variance from the applicable 

requirements is necessary. 

b. Where an alternative schedule is sought, the Owner shall submit a 

proposed schedule which demonstrates reasonable further progress 

and contains a date for final compliance as soon as practicable. If 

DES deems such a delay is reasonable under the cited circumstances, 

it shall grant the requested variance. 

c. Where an alternative reduction requirement is sought, the Owner 

shall submit information to substantiate an energy supply crisis, a 

major fuel disruption, an unanticipated or unavoidable disruption in 

the operations of the affected sources, or technological or economic 

infeasibility. DES, after consultation with the New Hampshire Public 

Utilities Commission, shall grant or deny the requested variance. If 

requested by the Owner, DES shall provide the owner with an 

opportunity for a hearing on the request. 

20. RSA 125-O:16, I MK1 & MK2 Economic Performance Incentives/Generation and Use of Early 

Emissions Reduction Credits: 

a. DES shall issue to the Owner early emissions reduction credits in the 

form of credits or fractions thereof for each pound of mercury or 

fraction thereof reduced below the baseline mercury emissions, on an 

annual basis, in the period prior to July 1, 2013. 

b. Ratios of early reductions credits to pounds of mercury reduced shall 

be as follows: 

i. 1.5 credits per pound reduced prior to July 1, 2008; 

ii. 1.25 credits per pound for reductions between July 1, 2008 and 

December 31, 2010; and 

iii. 1.1 credits per pound for reductions between January 1, 2011 and 

July 1, 2013. 

c. Reductions shall be calculated based upon the results of stack tests 

conducted, measurement by continuous emission monitoring, or other 

methodology approved by DES to confirm emissions during the time 

of operation of mercury reduction technology. 

d. Early emissions reduction credits may be banked by the Owner or 

utilized after July 1, 2013 to meet the reduction requirement of RSA 

125-O:13, II as allowed under RSA 125-O:13, VII. 

e. Early emissions reduction credits are not sellable or transferable to 

non-affected sources; however, upon the July 1, 2013 compliance 

date, the Owner may request a one-for-one conversion of early 

emissions reduction credits to over-compliance credits. 
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Temporary Permit TP-0008 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

f. Should a federal rule applicable to mercury emissions at one or more 

of the affected sources be enacted with an implementation date prior 

to July 1, 2013, then early reduction credits may only be earned for 

emissions reductions that exceed the level required by the federal rule 

of the affected sources in aggregate or the baseline mercury emissions 

level, whichever is lower, at the same ratios listed in subparagraph (b) 

above. 

g. Early emissions reduction credits shall not be used for compliance 

with the requirement of RSA 125-O:13, II prior to the installation of 

FGD technology, and shall not be used as a means to delay the 

installation of the FGD technology. 

21. RSA 125-O:16, II MK1 & MK2 Economic Performance Incentives/ Use of Over-Compliance Credits: 

a. DES shall issue to the Owner over-compliance credits in the form of 

credits or fractions thereof for each pound of mercury or fraction 

thereof reduced in excess of the emissions reduction requirement of 

RSA 125-O:13, II, on an annual basis, following the compliance date 

of July 1, 2013. 

b. The ratios of over-compliance credits to excess pounds of mercury 

reduced shall be as follows: 

i. 0.5 credits per pound reduced for reductions between 80 and 85 

percent; 

ii. 1 credit per pound reduced for reductions between 85 and 90 

percent reduction; and 

iii. 1.5 credits per pound reduced for reductions of 90 percent or 

greater. 

c. Over-compliance credits may be banked for future use. The 

requirements of RSA 125-O:13, V shall not alter the emissions levels 

at which over-compliance credits are earned. 

d. Should a federal rule applicable to mercury emissions at one or more 

of the affected sources be enacted, then over-compliance credits may 

only be earned for emissions reductions that exceed the level required 

by the federal rule of the affected sources in aggregate or the 

requirement of RSA 125-O:13, II, whichever is lower, at the same 

ratios listed in subparagraph (b) above. 

e. At the request of the Owner, over-compliance credits may be 

surrendered by the owner to the department and SO2 allowances shall 

be transferred to the owner at a rate of 55 tons SO2 allowances for 

every one over-compliance credit. Transfer shall be limited to a 

maximum of 20,000 total tons SO2 allowances transferred in a given 

year, defined as the sum of all SO2 allowances received by the 

affected sources under RSA 125-O:4, IV(a)(2) and IV(a)(3), and 

under this subparagraph. SO2 allowances shall be credited to the 

affected sources' accounts in the following year in accordance with 

RSA 125-O:4, IV(a)(4). 
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Temporary Permit TP-0008 

Table 4 – Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

22. Env-A 604.02 MKLC1 The limestone processing rate of the wet limestone ball mills shall not 

exceed 25 tons per hour7

. 

B. Initial Compliance Demonstration Requirements 

The Owner shall demonstrate initial compliance with the emission limitations specified in Table 

4 for the parameters contained in Table 5 below, within 60 days after achieving stable FGD 

operation with both MK1 and MK2 exhausting through stack STMK3. The Owner shall perform 

the initial compliance demonstration requirements listed in Table 5 below. In addition, the 

Owner shall perform all monitoring and testing requirements in Table 6 to ensure compliance 

with emissions and operating limitations contained in Table 4. 

Table 5: Initial Compliance Demonstration Requirements 

Item 

No. 

Applicable 

Emission 

Unit 

Parameter Method of Compliance Frequency 

of Method 

Regulatory 

Basis 

1. MK1 & MK2 

with MK2-

PC7 

Performance 

tests for 

mercury 

a. The Owner shall conduct initial 

performance tests for mercury to 

demonstrate compliance with the 

respective mercury emissions limitation in 

Table 4, Item 13. 

b. Testing shall be conducted and the results 

reported in accordance with 40 CFR 60, 

Sections 60.8(a), (b), (d), (e), and (f), and 

Appendix A. The following test methods 

or DES approved alternatives shall be used 

for the pollutants specified: 

i. Method 1 or 2 to determine exit 

velocity of stack gases; 

ii. Method 3 or 3A to determine carbon 

dioxide, oxygen, excess air, and 

molecular weight (dry basis) of stack 

gases; 

iii. Method 4 to determine moisture 

content (volume fraction of water 

vapor) of stack gases; 

Within 60 

days after 

achieving 

stable FGD 

operation 

with both 

MK1 and 

MK2 

exhausting 

through stack 

STMK3 

Env-A 802 & 

40 CFR 60.8 

(a), (b), (d)-

(f) 

 

7

 The limestone processing equipment subject to this requirement consists of two wet limestone ball mills. Only one wet limestone ball 

mill is operated at a time. The second wet limestone ball mill will serve as a backup unit. 
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Temporary Permit TP-0008 

Table 5: Initial Compliance Demonstration Requirements 

Item 

No. 

Applicable 

Emission 

Unit 

Parameter Method of Compliance Frequency 

of Method 

Regulatory 

Basis 

iv. For mercury, in accordance with the 

mercury monitoring requirement of 

RSA 125-O:15 and Table 6, Item 3 of 

this permit. 

2. MK1 & MK2 Performance 

Test for SO2

a. The Owner shall conduct an initial 

performance test for SO2 to demonstrate 

compliance with the respective SO2

emissions limitation in Table 4, Items 6 

and 8. 

b. Testing shall be conducted and the results 

reported in accordance with 40 CFR 60, 

Sections 60.8(a), (b), (d), (e), and (f), and 

Appendix A. The following test methods 

or DES approved alternatives shall be used 

for the pollutants specified: 

i. Use of certified CEMS monitors. With 

the use of CEMS monitors, compliance 

will be determined based on a monthly 

average of CEMS data. 

Within 60 

days after 

achieving 

stable FGD 

operation 

with both 

MK1 and 

MK2 

exhausting 

through stack 

STMK3 

Env-A 802 & 

40 CFR 60.8 

(a), (b), (d)-

(f) 

3. MK1 & MK2 General Stack 

Testing 

Requirements 

Compliance testing shall be planned and carried 

out in accordance with the following schedule: 

a. At the request of DES, submit to DES a 

pretest protocol at least 30 days prior to the 

commencement of testing which includes 

the following information: 

i. Calibration methods and sample data 

sheets; 

ii. Descriptions of the test methods to be 

used; 

iii. Pre-test preparation procedures; 

iv. Sample collection and analysis 

procedures; 

v. Process data to be collected; and 

vi. Complete test program description. 

b. At the request of DES, participate in a 

pretest conference with a DES 

representative at least 15 days prior to the 

test date. 

c. Emission testing shall be carried out under 

the observation of a DES representative. 

d. Within 60 days after completion of testing 

or within 15 days of receipt of test report, 

submit a copy of the test report to DES. 

Initial 

performance 

test and 

subsequent 

testing 

Env-A 

802.03, 

802.04, 

802.05, & 

802.11 

4. MK1 & MK2 General Stack 

Testing 

Requirements 

Operating Conditions During a Stack 

Emissions Test 

A compliance test shall be conducted under one 

Initial 

performance 

test and 

Env-A 

802.10 
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Table 5: Initial Compliance Demonstration Requirements 

Item 

No. 

Applicable 

Emission 

Unit 

Parameter Method of Compliance Frequency 

of Method 

Regulatory 

Basis 

of the following operating conditions: 

a. Between 90 and 100 % of maximum 

operating capacity; 

b. A production rate at which maximum 

emissions occur; or 

c. At such operating conditions agreed upon 

during a pre-test meeting conducted 

pursuant to Env-A 802.05. 

subsequent 

tests 

C. Monitoring/Testing Requirements 

1. The Owner is subject to the monitoring/testing requirements as contained in Table 6 below: 

Table 6 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

1. MK1 & 

MK2 

Continuous 

Emissions 

Monitoring 

Systems 

Site-Specific Monitoring Plan - Continuous 

Emissions Monitoring Systems 

a. The Owner shall submit a CEMS monitoring 

plan describing the proposed systems. The 

monitoring plan shall contain the 

information required under Env-A 808.04(c) 

and address all applicable monitoring 

requirements of Env-A 808, 40 CFR Part 60, 

and 40 CFR Part 75. 

b. The CEMS monitoring plan in item a above, 

shall at a minimum, address the following 

operating scenarios:

i. CEMS monitoring for units MK1 and 

MK2 when both units MK1 and MK2 are 

operating and emissions are discharged 

through the common exhaust stack 

STMK3;

ii. CEMS monitoring for compliance with 

the SO2 limitation specified in Table 4, 

Item 6 and 8;

iii.Monitoring for unit MK1 when emissions 

are discharged through stack STMK2 

(bypass stack).

At least 90 days 

prior to the 

installation of 

the CEM 

system 

Env-A 

808.04(a) 

2. MK1 & 

MK2 

Continuous 

Emissions 

Monitoring 

Systems 

Quality Assurance/Quality Control Plan 

Requirements 

The Owner of a source required by this part to 

install, operate, and maintain an opacity or gaseous 

As specified 

within 

regulation 

Env-A 808.06 
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Table 6 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

CEMS shall: 

a. Prepare a quality assurance/quality control 

(QA/QC) plan, which shall contain written 

procedures for implementation of its QA/QC 

 program for each CEMS; 

b. File the QA/QC plan with DES no later than 

the time specified in Env-A 808.05(e) after 

the initial startup of each CEMS; 

c. Review the QA/QC plan and all data 

generated by its implementation at least once 

each year; 

d. Revise or update the QA/QC plan, as 

necessary, based on the results of the annual 

review, by: 

ii. Documenting any changes made to the 

CEMS or changes to any information 

provided in the monitoring plan; 

iii. Including a schedule of, and describing, 

all maintenance activities that are 

required by the CEMS manufacturer or 

that might have an effect on the 

operation of the system; 

iiii. Describing how the audits and testing 

required by this part will be performed; 

and 

iiv. Including examples of the reports that 

will be used to document the audits and 

tests required by this part; 

e. Make the revised QA/QC plan available for 

review by DES at any time; and 

f. Within 30 days of completion of the annual 

QA/QC plan review, certify in writing that 

the Owner will continue to implement the 

source’s existing QA/QC plan or submit in 

writing any changes to the plan and the 

reasons for each change; 

g. Revision of the QA/QC plan is required if 

the results of emission report reviews, 

inspections, audits, review of the QA/QC 

plan, or any other information available to 

DES show that the plan does not meet the 

criteria specified in 40 CFR 60, Appendix F, 

Procedure 1, section 3; and 

h. The QA/QC plan shall be considered an 

update to the CEMS monitoring plan 
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Table 6 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

required by Env-A 808.04. 

3. MK1 & 

MK2 

Mercury 

Emissions 

Monitoring of Mercury Emissions 

a. Prior to the availability and operation of 

CEMS, and subsequent to the baseline 

emissions testing under RSA 125-O:14, II, 

stack tests or another methodology approved 

by DES shall be conducted twice per year to 

determine mercury emissions levels from the 

affected sources. 

b. Any stack tests performed shall employ a 

federally recognized and approved 

methodology, proposed by the Owner and 

employing a test protocol approved by DES. 

c. When a federal performance specification 

takes effect and a mercury CEMS capable of 

meeting the federal specifications becomes 

available, a mercury CEMS, approved by 

DES, shall be installed on STMK3 as 

deemed appropriate by DES. 

Twice per year 

or until a 

mercury CEMS 

is in operation 

and approved 

by DES 

RSA 125-O:15 

4. MK1 & 

MK2 

Stack flow, 

NOx, SO2, and 

CO2 (or O2), 

opacity 

The new stack (STMK3 from the FGD) serving 

units MK1 and MK2 shall be equipped with flow 

monitoring, NOx, SO2, and CO2 or O2 CEMS and 

a continuous opacity monitor (COMS)8. The 

CEMS and COMS shall meet 40 CFR 75 

requirements. 

Continuously Env-A 

808.02(a) 

(new) and 40 

CFR 75 

§75.10(a)(2), 

§75.12, and 

Env-A 

1211.03(f) 

5. MK2-PC7 FGD 

Operating 

Parameters 

a. The Owner shall continuously monitor the 

scrubber liquor pH and FGD absorber exit 

gas temperature. 

b. The Owner shall calibrate or validate the 

accurate operation of the instruments 

measuring the parameters a minimum of 

once annually in accordance with 

manufacturer’s recommended procedures or 

alternative procedures as approved by DES. 

All records of the calibrations or validations 

shall be kept and made available upon 

request. 

Continuously RSA 125-C:6, 

XI 

6. MK2-PC7 FGD Data 

Acquisition 

System 

The Owner shall have a data acquisition system 

for the FGD absorber exit gas temperature and 

scrubber liquor pH monitors, which calculates 

and monitors hourly averages and daily averages. 

 

Continuously RSA 125-C:6, 

XI 

 

8

 Due to excessive moisture in the flue gas exiting the FGD system, the COMS will be installed prior to the stack. 
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Table 6 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

7. MK1 & 

MK2 

Sulfur Test 

Method for 

Coal 

The owner or operator shall use Method ASTM 

D 4239-00 to determine the sulfur content of 

coal in pounds of sulfur per million BTU gross 

heat content. 

Each shipment 

of coal 

Env-A 806.04 

D. Recordkeeping Requirements 

The Owner is subject to the Recordkeeping requirements as contained in Table 7 below: 

Table 7 – Applicable Recordkeeping Requirements 

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

1. Record Retention and Availability 

The Owner shall keep the required records on 

file. These records shall be available for 

review by DES upon request. 

Retain for a 

minimum of 5 years

Emissions Units 

specified in 

Table 1 and 

Pollution 

Control 

Equipment 

specified in 

Table 3 

Env-A 902 

2. General Recordkeeping Requirements for 

Process Operations 

The Owner shall keep monthly records of: 

a. The quantity of limestone used as 

documented by limestone delivery records; 

and 

b. The hours of operation of the wet 

limestone ball mills. 

Monthly MKLC1 

MK2-PC7 

Env-A 903.02 

3. The Owner shall maintain the standard 

operating and maintenance procedures for the 

air pollution control equipment in a convenient 

location (e.g., control room/technical library) 

and make them readily available to DES upon 

request. 

Maintain at facility 

at all times 

MK2-PC7 Env-A 906.01 

4. CEMS and Other Approved Monitoring 

Methods Recordkeeping Requirements 

a. The Owner shall record and maintain the 

information pursuant to 40 CFR Part 75, 

which includes the certification, quality 

assurance, and quality control records. 

b. The Owner shall record and maintain 

CEMS records according to the most 

stringent requirements of Env-A 808 and 40 

CFR Part 75. 

As specified by 

regulation 

MK1, MK2, 

MK2-PC7 

Env-A 903.04 

Env-A 808 

40 CFR Part 75 
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Table 7 – Applicable Recordkeeping Requirements 

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

5. The Owner shall record the hours of operation 

of MK1 and MK2 as follows: 

a. Total hours of MK1 and MK2 each; and 

b. Total hours of MK1 when discharging 

through STMK2 (bypass stack) 

Monthly MK1 and MK2 Env-A 906 

6. The owner or operator shall maintain the 

following sulfur analysis records: 

a. Records showing the maximum weight 

percentage sulfur and quantity of each fuel 

delivery shipment received; and 

b. Records showing either: 

1. The analytical method used and the 

specified fuel analysis results of the 

shipment or consignment from which 

the shipment came; or 

2. Delivery records sufficient to allow 

for traceability of the analytical results 

corresponding to each shipment 

received by the stationary source, 

showing: 

 i. The date of delivery; 

 ii. The quantity of delivery; 

 iii. The type of fuel; 

iv. The maximum weight percentage 

sulfur; and 

v. The name, address, and telephone 

number of the company making the 

delivery. 

Each shipment of 

coal 

MK1 & MK2 Env-A 806.05 
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E. Reporting Requirements 

The Owner is subject to the reporting requirements identified in Table 8 below: 

Table 8 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory Cite 

1. Performance Test Reports

The Owner shall submit a report to DES 

documenting the results of the compliance stack 

emission test. The compliance stack emission test 

report shall contain the following information: 

a. All the information required for the pre-test 

protocol as described in Env-A 802.04; 

b. All test data; 

c. All calibration data; 

d. Process data agreed by DES and the Owner to 

be collected; 

e. All test results; 

f. A description of any discrepancies or 

problems that occurred during testing or 

sample analysis; 

g. An explanation of how discrepancies or 

problems were treated and their effect on the 

final results; and 

h. A list and description of all equations used in 

the test report, including sample calculations 

for each equation used. 

No later than 60 

days after a 

performance test 

MK1, MK2 & 

MK2-PC7 

Env-A 802.11 

2. Quarterly Reports 

The Owner shall submit to DES no later than 30 

calendar days after the end of the calendar 

quarter, the information required in Table 7, Item 

4. 

Quarterly – 30 

calendar days after 

the end of the 

calendar quarter 

MK1, MK2, 

MK2-PC7 

40 CFR 75, 

Env-A 808.11 

3. Semi-annual Report 

The Owner shall submit to DES the following 

information on a semi-annual basis: 

a. Hours of operation of MK1 and MK2 as 

required in Table 7, Item 5; and 

b. Limestone records as required in Table 7, 

Item 2. 

Semi-annual MK1, MK2, 

MKLC1 

Env-A 910 

4. Annual Emissions Compliance Report for 

Mercury 

The Owner shall submit to DES a report of annual 

mercury emissions from the affected sources to 

demonstrate compliance with Item 13 of Table 4. 

 This report shall include all references and 

methodologies used to calculate the total mercury 

emissions from the affected sources. 

Annually by April 

15th of each 

calendar year 

Affected 

Sources as 

defined in RSA 

125-O:12 

Env-A 910 
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Table 8 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory Cite 

5. Quarterly Coal Report 

The Owner shall submit to DES no later than 30 

calendar days after the end of the calendar 

quarter, the information required in Table 7, Item 

6. Submittal of the “Monthly Report of Cost and 

Quality of Fuel for Electric Plants,” will satisfy 

the requirements of this condition. 

Quarterly – 30 

calendar days after 

the end of the 

calendar quarter 

MK1 & MK2 Env-A 910.01 

VII. Administrative Permit Amendments

A. Pursuant to Env-A 612.01, the Owner may implement the changes addressed in the request for an 

administrative permit amendment as defined in Part Env-A 100 immediately upon submittal of 

the request. 

B. Pursuant to Env-A 612.01, the Director shall take final action on a request for an administrative 

permit amendment in accordance with the provisions of Env-A 612.01(b) and (c). 

VIII. Minor Permit Amendments

A. Pursuant to Env-A 612.03, the owner or operator of a source or device shall submit to the 

department a request for a minor permit amendment for any proposed change to an existing 

permit condition which will not result in an increase in the amount of a specific air pollutant 

currently emitted by the source or device and will not result in the emission of any regulated air 

pollutant or regulated toxic air pollutant currently not emitted by the source or device. 

B. The request for a minor permit amendment shall: 

1. Be in the form of a letter to the department; 

2. Describe the proposed change; and 

3. Describe any new applicable requirements that will apply if the change occurs. 

C. The department shall take final action on a request for a minor permit amendment within 90 days 

of receipt of such a request.

D. The owner or operator may implement the proposed change immediately upon filing a request for 

minor permit amendment with the department.

IX. Significant Permit Amendments

A. Pursuant to Env-A 612.04, the owner or operator shall submit an application to the department 

for a significant permit amendment for any proposed change to the physical structure or 

operation of the source or device covered by the temporary permit which increases the amount of 

a specific air pollutant currently emitted by such source or device or which results in the emission 

of any regulated air pollutant currently not emitted by such source or device. 
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B. A request for a significant permit amendment shall include the following: 

1. A complete application form, as described in Env-A 1703 through Env-A 1708, as applicable 

and provided by the department, containing all pertinent information with regard to the 

amendment including, if applicable, the information specified in Env-A 1709. 

2. The fee(s) specified in Env-A 702 through Env-A 705, as applicable. 

3. A description of: 

a. The proposed change; 

b. The emissions resulting from the change; and 

c. Any new applicable requirements that will apply if the change occurs: and 

4. Where air pollution dispersion modeling is required for a source or device pursuant to Env-A 

606.02, the information required pursuant to Env-A 606.03. 

C. The department shall take take final action on a request for a significant permit amendment 

within 90 days of receipt of such a request, provided that the public notice and hearing 

procedures specified in Env-A 621 have been satisfied. 

D. The owner or operator shall not implement the proposed change until the department issued the 

amended permit. 

X. Emission-Based Fee Requirements

A. The Owner shall pay an emission-based fee quarterly for this facility as calculated each calendar 

year pursuant to Env-A 705.03. 

B. The Owner shall determine the total actual annual emissions from the facility to be included in 

the emission-based multiplier specified in Env-A 705.03(a) for each calendar year in accordance 

with the methods specified in Env-A 616. 

C. The Owner shall calculate the annual emission-based fee for each calendar year in accordance 

with the procedures specified in Env-A 705.03 and the following equation:

Where: 

FEE = The annual emission-based fee for each calendar year as specified in Env-A 705. 

E = The emission-based multiplier is based on the calculation of total annual 

emissions as specified in Env-A 705.02 and the provisions specified in Env-A 

705.03(a). 

DPT = The dollar per ton fee the DES has specified in Env-A 705.03(b). 

CPIm= The Consumer Price Index Multiplier as calculated in Env-A 705.03(c). 

ISF = The Inventory Stabilization Factor as specified in Env-A 705.03(d). 

FEE * E = DPT * CPIm* ISF
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D. The Owner shall contact the DES each calendar year for the value of the Inventory Stabilization 

Factor. 

E. The Owner shall contact the DES each calendar year for the value of the Consumer Price Index 

Multiplier. 

F. The Owner shall submit, to the DES, payment of the emission-based fee and a summary of the 

calculations referenced in Sections X.B. and C. of this Permit for each calendar year. The total 

emission-based fee shall be paid in four equal installments on a quarterly basis. The quarterly 

payments shall be made in accordance with Env-A 705.04 on the 15th day of the following 

months: 

1. July of the year to which the fee applies (e.g., January, February, March 2007 emission fees 

are due July 15, 2007); 

2. October of the year to which the fee applies (e.g., April, May, June 2007 emission fees are 

due on October 15, 2007). 

3. January of the following year (e.g., July, August, September 2007 emission fees are due on 

January 15, 2008); 

4. April of the following year (e.g., October, November, December 2007 emission fees are due 

on April 15, 2008). 

The Owner shall pay any remaining balance of the total annual emission-based fee no later than 

April 15th of the following year. 

The emission-based fee and summary of the calculations shall be submitted to the following 

address: 

New Hampshire Department of Environmental Services 

Air Resources Division 

29 Hazen Drive 

P.O. Box 95 

Concord, NH 03302-0095 

ATTN.: Emissions Inventory 

G. The DES shall notify the Owner of any under payments or over payments of the annual emissionbased fee in accordance with Env-A 705.05. 
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XI. Permit Deviation 

In accordance with 40 CFR 70.6(a)(3)(iii)(B), the Owner shall report to the DES all instances of 

deviations from Permit requirements, by telephone, fax, or e-mail (pdeviations@des.state.nh.us) 

within 24 hours of discovery of such deviation. This report shall include the deviation itself, 

including those attributable to upset conditions as defined in this Permit, the probable cause of such

deviations, and any corrective actions or preventative measures taken. 

Within 10 days of discovery of the permit deviation, the Owner shall submit a written report 

including the above information as well as the following: preventive measures taken to prevent 

future occurrences; date and time the permitted device returned to normal operation; specific device, 

process or air pollution control equipment that contributed to the permit deviation; type and quantity

of excess emissions emitted to the atmosphere due to permit deviation; and an explanation of the 

calculation or estimation used to quantify excess emissions. 

Said Permit deviation shall also be submitted in writing to the DES in the semi-annual summary 

report of monitoring and testing requirements due July 31st and January 31st of each calendar year. 

Deviations are instances where any Permit condition is violated and has not already been reported as 

an emergency pursuant to 40 CFR 70.6(g). 

Reporting a Permit deviation is not an affirmative defense for action brought for noncompliance.