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, July 8, 2011, July 18, 2012, August 14, 2013 & September 26, 2014

Significant Permit Amendment: December 4, 2014

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. Date Received Purpose

FY07-0103 June 7, 2007 Temporary Permit TP-0008

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

11-0078 June 3, 2011 Request for the reissuance of Temporary Permit

12-0113 July 2, 2012 Request for the reissuance of Temporary Permit

13-0088

14-0283

June 13, 2013

July 21, 2014

Request for the reissuance of Temporary Permit

Significant Permit Amendment

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, 2015.

 ________________________________

 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................................................................ 7

A. Significant Activity Identification........................................................................................................... 7

B. Stack Criteria ......................................................................................................................................... 9

V. POLLUTION CONTROL EQUIPMENT/METHOD IDENTIFICATION .................................................................. 10

VI. APPLICABLE REQUIREMENTS.................................................................................................................... 10

A. Operational and Emission Limitations ................................................................................................ 10

B. Initial Compliance Demonstration Requirements................................................................................ 17

C. Monitoring/Testing Requirements........................................................................................................ 22

D. Recordkeeping Requirements............................................................................................................... 25

E. Reporting Requirements....................................................................................................................... 27

VII. ADMINISTRATIVE PERMIT AMENDMENTS ................................................................................................. 29

VIII. MINOR PERMIT AMENDMENTS ................................................................................................................. 29

IX. SIGNIFICANT PERMIT AMENDMENTS......................................................................................................... 30

X. EMISSION-BASED FEE REQUIREMENTS ..................................................................................................... 30

XI. PERMIT DEVIATION .................................................................................................................................. 32
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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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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

tph tons per hour

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. 

Application 14-0283 Significant Permit Amendment

On June 20, 2014, DES has proposed to amend Temporary Permit TP-0008 because the permit did 

not include applicable requirements of the Code of Federal Regulations (CFR), 40 CFR Part 60 

Subpart OOO, Standards of Performance for Nonmetallic Mineral Processing Plants (Subpart 

OOO), for the Limestone Processing and Handling System. On July 21, 2014, PSNH has consented 

to the proposal to amend the permit and submitted an application. The purpose of this permitting 

project is to add the applicable requirements of Subpart OOO for the limestone handling and 

processing system. The amended permit also removes permit conditions restricting the limestone 

processing and handling system to using only one of two wet ball mills at a time, and limiting total 

throughput to less than 25 tons per hour.

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.
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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.

MKLC1 Limestone 

Processing and 

Handling System

Not Applicable See Table 1A below.

 

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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Table 1A - Limestone Processing and Handling System5

Equipment 

ID

Equipment Description Year 

Installed

Design 

Capacity

Control Device

L-1 Limestone belt conveyor (30") to 

receiving hopper 

2012 200 tons per 

hour (tph)

Dust suppression enclosure 

with dust suppression spray 

(LDS-1)

RS-C Radial Stacker Conveyor C (48") to

Limestone belt conveyor L-2 (via 

hopper)

Original 

 1961

1400 tph Dust suppression enclosure 

limestone product delivered 

wet

L-2 Limestone belt conveyor (48") to 

Limestone Storage Silo

2011 1400 tph Dust suppression enclosure 

with dust suppression spray 

(LDS-2)

L-2A Limestone belt conveyor (48") to 

Limestone Storage Silo 

2011 1400 tph Dust suppression enclosure 

with dust suppression spray 

(LDS-2)

LSS-1 Limestone Storage Silo # 1 2011 7500 tons Baghouse (N011)

LSS-2 Limestone Storage Silo # 2 2011 7500 tons Baghouse (N005)

L-3A Limestone Storage Silo unloading 

conveyor, indoors (30") 

2011 150 tph Dust suppression enclosure 

with dust suppression spray 

(LDS-2)

L-3B Limestone Storage Silo unloading 

conveyor, indoors (30") 

2011 150 tph Dust suppression enclosure 

with dust suppression spray 

(LDS-2)

L-3C Limestone belt conveyor (30") from 

silo storage to conveyor L-4 at 

Transfer Tower (TT-1) 

2011 150 tph Dust suppression enclosure 

and dust suppression spray 

Transfer Tower #1 (LDS-2)

RC-1 Limestone Transfer Tower (TT-1) 

Maintenance Recirculation Chute to 

Dump Truck

2013 20 tph Dust suppression enclosure 

and dust suppression spray 

Transfer Tower #1 (LDS-2)

L-4 Limestone belt conveyor (30") from 

silo storage via TT-1 to Transfer 

Tower (TT-2)

2011 150 tph Dust suppression enclosure 

and dust suppression spray 

Transfer Tower #2 (LDS-2)

L-5 Limestone belt conveyor (30") from 

TT-2 to Day Silos 

2011 150 tph Dust suppression enclosure 

and dust suppression spray 

Transfer Tower #2 (LDS-3)

BF-2 Belt Feeder (30") for emergency 

limestone silo feed from truck to 

conveyor L-5

2011 50 tph Dust suppression enclosure 

and spray at Transfer Tower #2 

(LDS-3)

BE-1 Bucket Elevator for emergency 

limestone silo feed from truck to 

conveyor L-5

2011 50 tph Dust suppression enclosure 

and spray at Transfer Tower #2 

(LDS-3)

 

5

Equipment IDs 4000A, 4000B, 4030A, 4030B, 4060A and 4060B are located inside the FGD building. Emissions from baghouses 

4010A and 4010B are exhausted into the FGD building.
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Table 1A - Limestone Processing and Handling System5

Equipment 

ID

Equipment Description Year 

Installed

Design 

Capacity

Control Device

4000A Limestone Day Silo A 2011 300 tons Baghouse (4010A)

4000B Limestone Day Silo B 2011 300 tons Baghouse (4010B)

4030A Limestone Feeder A 2011 18.5 tph N/A - Water injection 

4030B Limestone Feeder B 2011 18.5 tph N/A - Water injection 

4060A Ball Mill A 2011 18.5 tph N/A - Water injection 

4060B Ball Mill B 2011 18.5 tph N/A - Water injection 

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.
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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:

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. 1Env-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. 2Env-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. 3Env-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. 4Env-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 Env-A 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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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 
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Table 4 - Operational and Emission Limitations

Item 

No.

Regulatory 

Cite

Applicable Emission Unit Applicable Requirement

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.

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. 
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Table 4 - Operational and Emission Limitations

Item 

No.

Regulatory 

Cite

Applicable Emission Unit Applicable Requirement

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. 

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 
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Table 4 - Operational and Emission Limitations

Item 

No.

Regulatory 

Cite

Applicable Emission Unit Applicable Requirement

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-forone conversion of early emissions reduction credits to overcompliance credits. 

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 
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Item 

No.

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Applicable Emission Unit Applicable Requirement

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 overcompliance 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).

22. 40 CFR 

60.672(b)

(Subpart OOO)

MKLC1

Transfer points from:

 RS-C to L-2

 L-1 to L-2 

 L-2 to L-2A

 BF-2 to BE-1

 BE-1 to L-5

NSPS for Nonmetallic Mineral Processing Plants - Standard 

for Particulate matter

a. Fugitive emissions from affected facilities other than 

crushers that are not enclosed in a building:

The average opacity from any transfer point on a belt 

conveyor or from any other affected facility installed after 

April 22, 2008, shall not exceed 7 percent7.

40 CFR 

60.672(b)

& 

40 CFR 

60.672(e)

MKLC1

 Transfer point from 

L-3C to L-4 located inside 

the transfer tower TT-1

 Transfer point from 

L-4 to L-5 located inside 

the transfer tower TT-2

 Transfer points located 

inside the silo building:

 Limestone silo LSS-1 to 

L-3A or L-3B

 Limestone silo LSS-2 

to L-3A or L-3B

b. Fugitive emissions from affected facilities other than 

crushers that are enclosed in a building:

If any transfer point on a conveyor belt or any other affected 

facility is enclosed in a building, then each enclosed 

affected facility must comply with the emission limit

identified in Item 22.a or the building enclosing the affected 

facilities must comply with the following emission limits:

i. Fugitive emissions from the building openings (except 

for vents8) must not exceed 7 percent opacity; and

ii. Vents in the building must meet the particulate matter 

emission limit of 0.014 gr/dscf.

 

7

Compliance with visible emission limitations shall be determined using 40 CFR 60, Appendix A, Method 9 as described in Table 5, 

Item 6.

8

Per 40 CFR 60.671, Vent means an opening through which there is mechanically induced air flow for the purpose of exhausting from 

a building air carrying particulate matter emissions from one or more affected facilities.
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Item 

No.

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Applicable Emission Unit Applicable Requirement

 L-3A to L-3C & L-3B 

to L-3C 

 Transfer points located 

inside the FGD building:

 Day silo A to belt

feeder A

 Day silo B to belt 

feeder B.

40 CFR 

60.672(b)

MKLC1 (Ball Mills -

4060A & 4060B)

c. Fugitive emissions from crushers that are enclosed in a 

building:

The opacity of fugitive emissions from each crusher shall 

not exceed 12% or the building enclosing the affected 

facilities must comply with the emission limits identified in 

Item 22.b.i. and ii.

40 CFR 

60.672(f) 

MKLC1 (LSS1 & LSS2) d. Emissions from a baghouse that controls individual, 

enclosed storage bins:

The opacity of emissions from any baghouse that controls 

emissions from an individual, enclosed storage bin shall not 

exceed 7%.

40 CFR 

60.672(e) & (f)

MKLC1 (4000A & 4000B) e. The opacity of emissions from any baghouse that controls 

emissions from an individual, enclosed storage bin shall not 

exceed 7% or the building enclosing the affected facilities 

must comply with the emission limits identified in Item 

22.b.i. and ii.

23. 40 CFR 

60.672(d)

MKLC1 Truck dumping of nonmetallic materials into any screening 

operation, feed hopper, or crusher is exempt from the 

requirements of Subpart OOO.

24. 40 CFR 

60.670(d)

MKLC1 NSPS for Nonmetallic Mineral Processing Plants - Equipment 

Replacement

The Owner or Operator shall be allowed to replace a component 

of the facility with new equipment of equal or smaller capacity, 

having the same function as the existing equipment by 

complying with the reporting requirements of Table 8, Item 7, 

provided there is no increase in the amount of emissions. The 

Owner or Operator may implement the equipment replacement 

immediately upon filing the report.

25. 40 CFR 

60.11(d) & (g) 

Subpart A

MKLC1 NSPS General Provisions 

a. At all times, including periods of startup, shutdown, and 

malfunction, owners and operators shall, to the extent 

practicable, maintain and operate any affected facility 

including associated air pollution control equipment in a 

manner consistent with good air pollution control practice 

for minimizing emissions. Determination of whether 

acceptable operating and maintenance procedures are being 

used will be based on information available to the 
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Table 4 - Operational and Emission Limitations

Item 

No.

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Applicable Emission Unit Applicable Requirement

Administrator which may include, but is not limited to, 

monitoring results, opacity observations, review of operating

and maintenance procedures, and inspection of the source;

b. For the purpose of submitting compliance certifications or 

establishing whether or not a person has violated or is in 

violation of any standard in this part, nothing in this part 

shall preclude the use, including the exclusive use, of any 

credible evidence or information, relevant to whether a 

source would have been in compliance with applicable 

requirements if the appropriate performance or compliance 

test or procedure had been performed.

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;

iv. For mercury, in accordance with the 

mercury monitoring requirement of 

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

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)
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Table 5: Initial Compliance Demonstration Requirements

Item 

No.

Applicable 

Emission 

Unit

Parameter Method of Compliance Frequency 

of Method

Regulatory

Basis

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 & 

MKLC1

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 & 

MKLC1

General Stack 

Testing 

Requirements

Operating Conditions During a Stack 

Emissions Test

A compliance test shall be conducted under one 

of the following operating conditions:

a. Between 90 and 100 % of maximum 

operating capacity;

Initial 

performance 

test and 

subsequent 

tests

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

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.

5. MKLC1 General Stack 

Testing 

Requirements

Visible Emissions Testing Pursuant to 

40 CFR 60 Subpart OOO 

The Owner or Operator shall notify the 

Department at least 30 days prior to conducting 

the required performance testing by providing 

the following:

a. The name, mailing address, telephone 

number and contact information of the 

owner of the non-metallic processing 

plant;

b. The address of the physical location where 

the non-metallic processing plant will be 

operated; and

c. For each piece of equipment, including but 

not limited to grinding mills, bucket 

elevators, loading stations and conveyors 

that is a component of the non-metallic 

processing plant, the following 

information:

i. A description of the equipment;

ii. The manufacturer of the equipment;

iii. The serial number of the equipment; 

and

iv. The maximum throughput of the 

equipment.

Initial 

performance 

test

Env-A 

802.12 

6. MKLC1 Particulate 

matter & 

Opacity

a. Affected facilities enclosed in a building:

The Owner or Operator shall determine 

compliance with the PM standards for any 

affected facility that is enclosed in a 

building as follows:

i. Except as specified in 40 CFR

60.675(e)(3) and (4), EPA Methods 5 

or 17 shall be used to determine the 

particulate matter concentration from 

each building vent. The sample volume 

shall be at least 1.70 dscm (60 dscf). 

For Method 5, if the gas stream being 

sampled is at ambient temperature, the 

sampling probe and filter may be 

operated without heaters. If the gas 

Initial 

performance 

test within 

180 days 

after the 

issuance of 

significant 

amendment

40 CFR 

60.675
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Table 5: Initial Compliance Demonstration Requirements

Item 

No.

Applicable 

Emission 

Unit

Parameter Method of Compliance Frequency 

of Method

Regulatory

Basis

stream is above ambient temperature, 

the sampling probe and filter may be 

operated at a temperature high enough, 

but no higher than 121 °C (250 °F), to 

prevent water condensation on the 

filter.

ii. To demonstrate compliance with the 

fugitive emission limits for buildings 

specified in Table 4, Item 22.b.i, the 

Owner or Operator must conduct an 

initial Method 9 performance test 

according to Item 6.b below and 

40 CFR 60.11.

iii. Performance tests must be conducted 

while all affected facilities inside the 

building are operating.

MKLC1 Opacity b. Procedures for determining compliance 

with opacity standard: In determining 

compliance with the opacity standard in 

Table 4, Item 22, the Owner or Operator 

shall use Method 9 and the procedures in 

40 CFR 60.11, with the following 

additions:

i. The minimum distance between the 

observer and the emission source shall 

be 4.57 meters (15 feet).

ii. The observer shall, when possible, 

select a position that minimizes 

interference from other fugitive 

emission sources (e.g., road dust). The 

required observer position relative to 

the sun (Method 9, Section 2.1) must 

be followed.

iii. For affected facilities using wet dust 

suppression for particulate matter 

control, a visible mist is sometimes 

generated by the spray. The water mist 

must not be confused with particulate 

matter emissions and is not to be 

considered a visible emission. When a 

water mist of this nature is present, the 

observation of emissions is to be made 

at a point in the plume where the mist 

is no longer visible.

c. When determining compliance with the 

fugitive emissions standard for any 
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Table 5: Initial Compliance Demonstration Requirements

Item 

No.

Applicable 

Emission 

Unit

Parameter Method of Compliance Frequency 

of Method

Regulatory

Basis

affected facility described under 40 CFR 

60.672(b) or §60.672(e)(1), the duration of 

the Method 9 observations must be 30 

minutes (five 6-minute averages). 

Compliance with the applicable fugitive 

emission limits in Table 4, Item 22 must 

be based on the average of the five 6-

minute averages.

MKLC1 Opacity d. Baghouses that control emissions from 

individual storage bins: In determining 

compliance with the opacity of stack 

emissions from any baghouse that controls 

emissions only from an individual 

enclosed storage bin under 40 CFR 

60.672(f), using Method 9, the duration of 

the Method 9 observations shall be 1 hour 

(ten 6-minute averages). The duration of 

the Method 9 observations may be reduced 

to the duration the affected facility 

operates (but not less than 30 minutes) for 

baghouses that control storage bins that 

operate for less than 1 hour at a time.

MKLC1 PM & 

Opacity

e. Alternatives: For the above required 

performance tests, the Owner or Operator 

may use the alternative methods and 

procedures specified in 40 CFR 60.675(e). 
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C. Monitoring/Testing Requirements

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 

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 

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

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 

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. 

Twice per 

year or until a 

mercury 

CEMS is in 

operation and 

approved by 

DES

RSA 125-

O:15
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Table 6 – Monitoring/Testing Requirements

Item 

No.

Device Parameter Method of Compliance Frequency 

of Method

Regulatory 

Cite

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.

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)9. 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

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

8. MKLC1

Transfer points 

from:

 RS-C to L-2

 L-1 to L-2 

 L-2 to L-2A

 BF-2 to BE-1

 BE-1 to L-5

Visible 

emissions 

testing 

The Owner or Operator shall conduct emissions 

testing to evaluate compliance with the visible 

emission limitations in Table 4, Item 22.a. 

Testing shall be conducted in accordance with 

Table 5, Items 4, 5 and 6.

Within 5 

years from the 

previous 

performance 

test

40 CFR 

60.675 & 

Table 3 of 

Subpart OOO

9. MKLC1 

(4000A, 4000B, 

Visible 

emissions

a. The owner or operator of any affected 

facility for which construction, 

Quarterly (if 

the affected 

40 CFR 

 

9

 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

LSS1 & LSS2) modification, or reconstruction commenced 

on or after April 22, 2008, that uses a 

baghouse to control emissions must conduct 

quarterly 30-minute visible emissions 

inspections using EPA Method 22.

b. The Method 22 test shall be conducted 

while the baghouse is operating. The test is 

successful if no visible emissions are 

observed.

c. If any visible emissions are observed, the 

owner or operator of the affected facility 

must initiate corrective action within 24 

hours to return the baghouse to normal 

operation. The owner or operator must 

record each Method 22 test, including the 

date and any corrective actions taken, in the 

logbook required under Table 7, Item 7. 

facility is 

operated 

during the 

calendar 

quarter)

60.674(c)

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 the 

quantity of limestone used as documented by 

limestone delivery records.

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
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Table 7 – Applicable Recordkeeping Requirements

Item 

No.

Recordkeeping Requirement Frequency of 

Recordkeeping

Applicable 

Emission Unit

Regulatory Cite

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

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

7. The Owner or Operator must record each 

periodic inspection required under Table 6, 

Item 9, including dates and any corrective 

actions taken, in a logbook (in written or 

electronic format). The owner or operator must 

keep the logbook onsite and make hard or 

electronic copies (whichever is requested) of 

the logbook available to DES/EPA upon 

request.

Maintain on a 

continuous basis

MKLC1 40 CFR 60.676(b)
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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

6. NSPS Subpart OOO Test Reports

a. No later than 60 days after the particulate 

matter and visible emissions testing is 

performed, file with the department a 

summary report of the results of the visible 

emissions testing that includes the following:

i. The emission points that were observed 

and where visible emissions were 

assessed;

ii. The rate of processing of material through 

the non-metallic mineral processing plant 

during the test;

iii. An indication of whether each emission 

point passed or failed the visible 

emissions test;

iv. The name of the person that performed 

the visible emissions testing, and the date 

the person was most recently certified to 

perform US EPA Test Method 9 prior to 

the date of the test; and 

v. A copy of the Method 9 certification for 

the person(s) that performed the visible 

emissions test; and

b. Retain the data sheets completed during the 

visible emissions testing by the US EPA 

Method 9-certified observer at the facility and 

make such data sheets available to the 

department upon request.

No later than 60 

days after a 

performance test

MKLC1 Env-A 802.12 & 

40 CFR 60.676(f) 

7. NSPS for Nonmetallic Mineral Processing Plants 

- Equipment Replacement Reporting 

Requirements

Each Owner or Operator seeking to comply with 

Table 4, Item 24 shall submit to the Division the 

following information about the existing facility 

component being replaced and the replacement 

piece of equipment.

a. For a conveyor belt:

i. The width of the existing belt being 

As necessary MKLC1 40 CFR 

60.676(a)
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Temporary Permit TP-0008

Table 8 – Applicable Reporting Requirements

Item 

No.

Reporting Requirement Frequency of 

Reporting

Applicable 

Emission Unit

Regulatory Cite

replaced; and

ii. The width of the replacement conveyor 

belt.

b. For a storage bin:

i. The rated capacity in tons of the existing 

storage bin being replaced; and

ii. The rated capacity in tons of the 

replacement storage bin.

c. For a grinding mill or bucket elevator:

i. The rated capacity in tons per hour of the 

existing facility being replaced; and

ii. The rated capacity in tons per hour of the 

replacement equipment.

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.
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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.

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 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:
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 Merrimack Station 

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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).

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 FEE=E* DPT * CPIm* ISF
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Temporary Permit TP-0008

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.

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.