STATE OF NEW HAMPSHIRE 

Department of Environmental Services 

Air Resources Division 

Title V Operating Permit

Permit No: TV-OP-054 

Date Issued: March 9, 2007; Administrative Amendment issued on December 17, 2007. 

This certifies that: 

Northeast Utilities 

Public Service of New Hampshire 

780 North Commercial Street 

Manchester, NH 03101 

has been granted a Title V Operating Permit for the following facility and location: 

Public Service of New Hampshire 

Newington Station 

165 Gosling Road 

Newington, NH 

AFS Point Source Number – 3301500054 

This Title V Operating Permit is hereby issued under the terms and conditions specified in the Title V Operating Permit 

Application filed with the New Hampshire Department of Environmental Services on July 1, 1996 under the signature of 

the following responsible official certifying to the best of their knowledge that the statements and information therein are 

true, accurate and complete. 

Responsible Official: Designated Representative: 

John MacDonald John MacDonald (603) 634-2236

(603) 634-2236 Alternate Designated Representative:

Technical Contact: William Smagula (603) 634-2851 

Laurel Brown Authorized Account Representative:

(603) 634-2331 John MacDonald (603) 634-2236 

Alternate Authorized Account Representative: 

William Smagula (603) 634-2851 

This Permit is issued by the New Hampshire Department of Environmental Services, Air Resources Division 

pursuant to its authority under New Hampshire RSA 125-C and in accordance with the provisions of the Code 

of Federal Regulations, Title 40, Part 70. 

This Title V Operating Permit shall expire on March 31, 2012. 

SEE ATTACHED SHEETS FOR ADDITIONAL PERMIT CONDITIONS

For the New Hampshire Department of Environmental Services, Air Resources Division 

________ ____________________ 

 Director, Air Resources Division 
 PSNH Newington Page 2 

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TABLE OF CONTENTS

ABBREVIATIONS............................................................................................................................................... 4

FACILITY SPECIFIC TITLE V OPERATING PERMIT CONDITIONS ................................................... 6

I. FACILITY DESCRIPTION OF OPERATIONS ........................................................................................................ 6 

II. PERMITTED ACTIVITIES ........................................................................................................................... 6 

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

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

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

IV. INSIGNIFICANT ACTIVITIES IDENTIFICATION ............................................................................................ 8 

V. EXEMPT ACTIVITIES IDENTIFICATION ...................................................................................................... 8 

VI. POLLUTION CONTROL EQUIPMENT/METHOD IDENTIFICATION................................................................. 8 

VII. ALTERNATIVE OPERATING SCENARIOS.................................................................................................... 9 

A. Trial Test Burns with Other Fuels ......................................................................................................... 9

B. Fuel Blending Requirements (State Enforceable Only) ....................................................................... 10

C. Fly Ash Reinjection .............................................................................................................................. 11

D. NOx Emission Reduction Management Practices................................................................................ 11

E. Auxiliary Fuel – Toner ......................................................................................................................... 12

VIII. APPLICABLE REQUIREMENTS................................................................................................................. 13 

A. State-only Enforceable Operational and Emission Limitations........................................................... 13

B. Federally Enforceable Operational and Emission Limitations ........................................................... 13

C. Annual SO2 Allowance Programs (40 CFR 72, 40 CFR 73, Env-A 611.08, and Env-A 2900)............ 20

D. Ozone Season NOx Budget Trading Program (Env-A 3200)............................................................... 21

E. Annual and Non-Ozone Season NOx Allowance Program (Env-2900 and NOx RACT Order No. ARD98-001) ........................................................................................................................................................... 24

F. Multiple Pollutant Annual Budget Trading and Banking Program (Env-A 2900) [State Enforceable 

Only] 24

G. Discrete Emission Reduction Trading Program (Env-A 3100)............................................................ 27

H. Monitoring/Testing Requirements........................................................................................................ 28

I. Recordkeeping Requirements............................................................................................................... 43

J. Reporting Requirements....................................................................................................................... 49

IX. REQUIREMENTS CURRENTLY NOT APPLICABLE..................................................................................... 57 

GENERAL TITLE V OPERATING PERMIT CONDITIONS..................................................................... 58

X. ISSUANCE OF A TITLE V OPERATING PERMIT......................................................................................... 58 

XI. TITLE V OPERATING PERMIT RENEWAL PROCEDURES........................................................................... 58 

XII. APPLICATION SHIELD ............................................................................................................................ 58 

XIII. PERMIT SHIELD ..................................................................................................................................... 58 

XIV. REOPENING FOR CAUSE......................................................................................................................... 59 

XV. ADMINISTRATIVE PERMIT AMENDMENTS .............................................................................................. 60 

XVI. OPERATIONAL FLEXIBILITY ................................................................................................................... 60 

XVII. MINOR PERMIT AMENDMENTS .............................................................................................................. 62 

XVIII. SIGNIFICANT PERMIT AMENDMENTS .................................................................................................. 62 

XIX. TITLE V OPERATING PERMIT SUSPENSION, REVOCATION OR NULLIFICATION ....................................... 63 

XX. INSPECTION AND ENTRY........................................................................................................................ 63 

XXI. CERTIFICATIONS .................................................................................................................................... 63 

K. Compliance Certification Report ......................................................................................................... 63
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L. Certification of Accuracy Statement .................................................................................................... 64

XXII. ENFORCEMENT ...................................................................................................................................... 65 

XXIII. EMISSION-BASED FEE REQUIREMENTS............................................................................................... 65 

XXIV. DUTY TO PROVIDE INFORMATION...................................................................................................... 66 

XXV. PROPERTY RIGHTS ............................................................................................................................. 67 

XXVI. SEVERABILITY CLAUSE...................................................................................................................... 67 

XXVII. EMERGENCY CONDITIONS.................................................................................................................. 67 

XXVIII. PERMIT DEVIATION......................................................................................................................... 68 

FEDERAL ACID RAIN REQUIREMENTS ................................................................................................... 69

XXIX. PHASE II ACID RAIN PERMIT APPLICATION........................................................................................ 69 

XXX. GENERAL ACID RAIN PROVISIONS ..................................................................................................... 69 
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ABBREVIATIONS 

AAL Ambient Air 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 

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 

FR Federal Register 

HAP Hazardous Air Pollutant 

HHV High Heat Value 

HCl Hydrochloric acid 

Hr Hour 

kGal 1,000 gallons 

kscfm 1,000 standard cubic feet per minute 

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 

mg/L Milligrams per liter 

MMBTU (or MMBtu) Million British Thermal Units 

MMCF Million Cubic Feet 

MW Megawatt 

NAAQS National Ambient Air Quality Standard 

NATS NOx Allowance Tracking System 

NESHAPs National Emissions Standards for Hazardous Air Pollutants 
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ABBREVIATIONS (cont.) 

NG Natural Gas 

NHDES (or DES) New Hampshire Department of Environmental Services 

NMOC Nonmethane Organic Compound 

NOx Oxides of Nitrogen 

NSPS New Source Performance Standard 

NSR New Source Review 

PCB Polychlorinated biphenyls 

PE Potential Emission 

PM Particulate Matter 

PM10 Particulate Matter less than 10 microns diameter 

ppm part per million 

ppmv part per million by volume 

PSD Prevention of Significant Deterioration 

PSI Pounds per Square Inch 

PTE Potential to Emit 

PUC Public Utilities Commission 

RACT Reasonably Available Control Technology 

RTAP Regulated Toxic Air Pollutant 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

T-12M Tons during any consecutive 12-month period 

TAP Toxic Air Pollutant 

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 Title V Operating Permit Conditions 

I. Facility Description of Operations

Newington Station (Newington) is a fossil fuel-fired electric generating facility, owned and operated 

by Public Service of New Hampshire (PSNH), a subsidiary of Northeast Utilities. The facility is 

comprised of one utility boiler, two auxiliary boilers, one combustion turbine operating as an 

emergency generator, two bulk oil storage tanks, and one bulk oil storage day tank. The facility 

operations also include various activities that are classified as insignificant or exempt activities. 

The one utility boiler is capable of burning either natural gas or No. 6 fuel oil or crude oil; the 

auxiliary boilers burn No. 2 fuel oil; and the emergency generator burns No. 2 fuel oil. 

The auxiliary boilers provide steam and building heat when the utility boiler is not operating. The 

utility boiler stack is equipped with a CEMS for NOx, SO2, and CO and a COMS. Newington emits 

NOx, SO2, CO, VOCs, PM, CO2, RTAPs, and HAPs. Newington has installed control equipment 

and implemented operational changes to reduce emissions, including electrostatic precipitators to 

control particulate matter, and burner modifications (also referred to as low NOx burners), overfire 

air, staged combustion, and water injection, to control NOx emissions. 

Newington operates a fly ash reinjection system, as an alternative operating scenario, to capture 

unburned carbon and to reduce the amount of fly ash shipped off-site as solid waste. 

II. Permitted Activities

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

authorized to operate the devices and or processes identified in Sections III, IV, V and VI within the

terms and conditions specified in this Permit. 

III. Significant Activities Identification and Stack Criteria

A. Significant Activity Identification 

The activities identified in the following table (Table 1) are subject to and regulated by this Title 

V Operating Permit: 

Table 1 – Significant Activity Identification 

Emission 

Unit 

Number 

Description of 

Emission Unit 

Maximum Gross Heat Input or 

Maximum Power Output 

Maximum Operating Conditions 

NT1 Steam Generating Unit 1 

(Combustion 

Engineering Model No. 

8269) (Installed 1969) 

Tangential Firing 

Crude oil or No. 6 fuel oil at no more 

than 2.0% sulfur content by weight, No. 

2 fuel oil at no more than 0.4% sulfur 

content by weight, or natural gas or 

combination thereof: 4,350 MMBtu/hr 

gross heat input (nameplate rating)1

A) In accordance with New Source 

Review avoidance, the maximum 

operating rate shall not exceed 

25,235,000 MMBtu total gross 

heat input during any consecutive 

12-month period. This maximum 

 

1

 The heat input rating of 4,350 MMBtu/hr was calculated based upon the nameplate rating of NT1, fuel flow to the boiler, and Btu 
 PSNH Newington Page 7 

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Table 1 – Significant Activity Identification 

Emission 

Unit 

Number 

Description of 

Emission Unit 

Maximum Gross Heat Input or 

Maximum Power Output 

Maximum Operating Conditions 

operating rate may be adjusted 

upon written approval from DES. 

B) Toner may be used as an auxiliary 

fuel in the boiler. The toner feed 

rate shall not exceed 24 tons/day. 

NTAB1 Auxiliary Boiler No. 1A 

(Erie City Energy 

Division Model No. 

15Mkeystone) (Installed 

1969) 

No. 2 Fuel Oil with maximum sulfur 

content of 0.4% by weight: 99.4 

MMBtu/hr 

A) Maximum fuel consumption rate of 

No. 2 fuel oil shall not exceed 3.57 

million gallons during any 

consecutive 12-month period.2 

B) This fuel consumption limitation is 

to limit the NOx emissions to less 

than 50 tons during any 

consecutive 12-month period. 

NTAB2 Auxiliary Boiler No. 1B 

(Erie City Energy 

Division, Model No. 

15Mkeystone) (Installed 

1969) 

No. 2 Fuel Oil with maximum sulfur 

content of 0.4% by weight: 99.4 

MMBtu/hr 

A) Maximum fuel consumption rate of 

No. 2 fuel oil shall not exceed 3.57 

million gallons during any 

consecutive 12-month period.3 

B) This fuel consumption limitation is 

to limit the NOx emissions to less 

than 50 tons during any 

consecutive 12-month period. 

NTEG Emergency Generator I 

(International Harvester, 

Hi Solar, Model GS350) 

(Installed 1974) 

No. 2 Fuel Oil with a maximum sulfur 

content of 4% by weight. 

A) Operating hours shall be limited to 

500 hours during any consecutive 

12-month period. 

B) Maximum fuel consumption rate of 

No. 2 Fuel Oil shall not exceed 

17.1 gallons per hour and 8,550 

gallons during any consecutive 12-

month period.4

 

B. Stack Criteria 

The following stacks for the above listed significant devices at this facility shall discharge 

vertically without obstruction (including rain caps) and meet the following criteria: 

 

analysis of the fuel. The CEMS calculates and records the heat input on a minute-by-minute basis according to the procedures in 40 

CFR 75. The calculated heat input from the CEMS is based upon the volumetric flow of the stack gases, the CO2 concentration, and a 

carbon-based F factor—a default factor provided in 40 CFR Part 75. The calculated heat input rate from the CEMS is not based on 

fuel flow, except when dual fuels are used. 

2

 The heating value of No. 2 fuel oil is assumed to be 140,000 BTU/gallon. The fuel consumption limits may vary based on the actual 

heat content of the fuel burned. 

3

 The heating value of No. 2 fuel oil is assumed to be 140,000 BTU/gallon. The fuel consumption limits may vary based on the actual 

heat content of the fuel burned. 

4

 The heating value of No. 2 fuel oil is assumed to be 140,000 BTU/gallon. The fuel consumption limits may vary based on the actual 

heat content of the fuel burned. 
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Table 2 – Stack Criteria 

Stack 

Number 

Emission 

Unit 

Number 

Emission Unit 

Description 

Minimum Stack 

Height (Feet) 

Above Ground 

Level 

Maximum 

Inside Stack 

Diameter 

(Feet) 

STNT1 NT1 Steam Generating Unit No. 1 410 20.75 

STNTAB1 NTAB1 Auxiliary Boiler No. 1 211 3.5 

STNTAB2 NTAB2 Auxiliary Boiler No. 2 211 3.5 

Changes to the state-only requirements pertaining to stack parameters (set forth in this permit), 

shall be permitted only when an air quality impact analysis which meets the criteria of Env-A 

606 is performed either by the facility or the New Hampshire Department of Environmental 

Services, Air Resources Division (if requested by facility in writing) in accordance with the 

“DES-ARD Procedure for Air Quality Impact Modeling” and approved by DES. All air 

modeling data shall be kept on file at the facility for review by the DES upon request. 

IV. Insignificant Activities Identification

All activities at this facility that meet the criteria identified in Env-A 609.04(d), shall be considered 

insignificant activities. Emissions from the insignificant activities shall be included in the total 

facility emissions for the emission-based fee calculation described in Section XXIII. of this Permit. 

V. Exempt Activities Identification

All activities identified in Env-A 609.03(c) shall be considered exempt activities and shall not be 

included in the total facility emissions for the emission based fee calculation described in Section 

XXIII of this permit. 

VI. Pollution Control Equipment/Method Identification

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

techniques for each identified emissions unit: 

Table 3 – Pollution Control Equipment Method Identification5

Pollution 

Control 

Equipment 

Number 

Description of Equipment/Method Emission Unit 

Number 

NT1-PC1 Electrostatic Precipitator (ESP) NT1 

 

5

 Note that additional pollution control equipment/method options are included in the alternative operating scenario section. 
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VII. Alternative Operating Scenarios

While operating under an alternative operating scenario, the Permittee shall comply with all 

applicable requirements specified in this permit, including, but not limited to, state and federal 

operational and emission limitations specified in Section VIII.A.through G, monitoring and testing 

requirements specified in Section VIII. H., recordkeeping requirements specified in Section VIII. I, 

and reporting requirements specified in Section VIII. J. Pursuant to 40 CFR 70.6 (a)(9), the 

Permittee shall keep all applicable records pertaining to the alternative operating scenario during 

such operation. The Permittee shall keep a record of the scenario under which it is operating. 

A. Trial Test Burns with Other Fuels (Permit to Operate No. PO-B-1030) 

Prior to the use of any fuel other than fuels previously reviewed and approved by the DES, PSNH 

shall submit a proposal to the DES, which shall include, but not be limited to the following: 

1. Type of fuel; 

2. Analysis data of the fuel proposed, which shall include proximate and ultimate analysis, 

volatile and semi-volatile analyses (i.e., EPA Method 8240, 8260, 8250, or 8270) and metals 

analysis (i.e., Method 3050 and mercury). 

3. Specification of baseline operating conditions at Newington Station including fuel feed rate, 

sulfur content of fuel, ESP operating conditions, and emission values of opacity, SO2, NOx, 

particulate, and CO (if applicable); 

4. A comprehensive test plan, which shall present the proposed operating conditions for the 

trial burn, to include but not be limited to the following: 

a) Length of fuel trial; 

b) New fuel rate; 

c) Means of measuring new fuel feed; 

d) Description of new fuel feed process; 

e) New fuel preparations; 

f) Percent moisture of new fuel feed; 

g) Sulfur content of new fuel; 

h) Time table for operation stability; 

i) Existing fuel feed rate; 

j) ESP operating conditions; 

k) Expected emission values of opacity, SO2, NOx, TSP, and CO; 
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l) The continuous tracking or operational data prior to the fuel trial, during the fuel trial, and 

for a short time after the fuel trial. SO2, NOx, and opacity can be monitored using the 

existing CEM. 

m) A compliance stack test protocol for TSP emissions using Method 1 through 4, Method 5, 

or a DES approved alternate, when requested by DES. 

n) Operational parameters to be monitored and recorded, which shall include, but not be 

limited to steam flows, boiler temperatures, and oxygen; 

o) The effects of the new fuel on flyash characteristics and resulting effect on the ESP 

operation; 

p) The effects of the new fuel on bottom ash characteristics; 

q) Specification and description of expected operational and combustion conditions when 

the trial burn has reached stabilization with the new fuel feed; and 

r) A timetable or schedule with approximate dates of the trial test burn. 

5. Based on information regarding the proposed trial fuel burn provided by PSNH, DES may 

request additional specific information on the proposed trial burn operations. In addition, 

metal emission stack testing may be required dependent upon DES review of the new fuel 

metal analysis. 

6. If the new fuel is to be consumed on a regular basis, PSNH must apply for a temporary 

permit. As part of the temporary permit review process, DES will make a determination as 

to the applicability of the New Source Review and Prevention of Significant Deterioration 

programs, and will provide an opportunity for public notice and comment. 

7. DES shall respond within 30 days of receipt of a proposal with approval, conditional 

approval, denial, or request for additional information. 

8. DES Waste Management Division may have additional requirements and concerns and shall 

be contacted by PSNH prior to the initiation of any trial fuel burn. 

9. A summary report shall be submitted to DES within 60 days after the end of the trial fuel 

burn, which should include a summary of operational results and trends, emission values to 

include CEM and stack test data, if performed, and proposed future use of fuel. 

B. Fuel Blending Requirements (State Enforceable Only) (Permit to Operate No. PO-B-1030) 

DES grants PSNH a waiver from Env-A 1604 in order to purchase oil containing sulfur greater 

than 2.0% by weight. This oil shall be used for blending purposes only. PSNH shall comply 

with the requirements listed below when purchasing oil greater than 2.0% sulfur. 

1. Delivery of greater than 2.0% sulfur oil shall be to segregated storage tanks. 
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2. Greater than 2.0% sulfur oil shall be mixed with less than 2.0% sulfur oil in a tank in which 

the “sparging system” shall be in full operation to assure complete mixing of the blended oil. 

3. After mixing for an appropriate amount of time to assure complete blending, samples from 

the top, middle, and bottom of the tank shall be collected and analyzed in accordance with 

method ASTM D 4294. The sample results shall be averaged to create a composite figure in 

accordance with PSNH procedures. 

4. After sampling is complete and the test results indicate that the tank of blended oil is less 

than 2.0% sulfur by weight, the oil may be transferred to the Newington day tank. 

5. PSNH shall not burn oil containing greater than 2.0% sulfur by weight. 

6. Prior to accepting any shipment of oil containing greater than 2.0% sulfur by weight, PSNH 

shall contact DES by fax or telephone. 

7. PSNH shall provide DES with all analytical data from samples collected from all blending 

operations that utilize greater than 2.0% sulfur by weight oil. This data shall provide DES 

with specific sulfur analysis information on the oil feeding the boilers and confirm that each 

blend is less than or equal to 2.0% sulfur by weight. 

C. Fly Ash Reinjection (Permit to Operate No. PO-B-1030) 

1. To capture unburned carbon in the fly ash and to reduce the amount of ash shipped off-site 

as solid waste, PSNH is authorized to maintain and operate the fly ash injection system. 

2. The fly ash injection system is comprised of a system of blowers and piping that allow fly 

ash from the precipitator hoppers to be reinjected into the burners of the boilers. 

3. To minimize PM emissions during fly ash reinjection, PSNH shall ensure that the ESP is 

energized before start-up of the fly ash reinjection system. 

D. NOx Emission Reduction Management Practices (Permit to Operate No. PO-B-1030, NOx 

RACT Orders Nos. ARD-97-001 and ARD-98-001, and Env-A 1211) 

1. To achieve the NOx emission requirements specified in this permit, PSNH is authorized to 

maintain and operate any or all of following equipment, systems and methods: the overfire 

air system, water injection, and the low NOx burners. 

2. The CEMS shall be used to determine the NOx emissions from Unit No. 1. 

3. The overfire air system is comprised of ports, ducts, and dampers that allows the combustion 

airflow to be diverted from the top of the windbox through ports located above the top 

elevation of burners. 

4. The water injection system is comprised of nozzles that inject water into the flame to reduce 

peak flame temperature. 
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5. The low NOx burners are designed to create lower NOx emissions during the combustion of 

fuel. 

6. PSNH shall maintain compliance with the NOx emission limitations listed in Section VIII. 

B, D, E, and F during the usage of any of these alternative NOx emission reduction methods. 

 

7. PSNH shall record which NOx emission reduction management practice is in use and when 

a change in scenario occurs. 

8. PSNH shall maintain records according to Section VIII. I and submit reports according to 

Section VIII. J. 

E. Auxiliary Fuel – Toner (Permit to Operate No. PO-B-1030) (State Enforceable) 

Toner may be used as an auxiliary fuel. The combustion of the toner shall be performed under 

the following conditions: 

1. The toner feed rate shall not exceed 24 tons/day or a rate to ensure compliance with Env-A 

1400, whichever is less. 

2. PSNH shall ensure compliance with all federal and state air quality and waste management 

requirements pertaining to the combustion of toner. 

3. Combustion of toner shall not occur during start-up or shutdown conditions. 

4. Combustion of toner shall be ceased immediately upon indication of abnormal operating 

conditions or any condition that threatens compliance with this permit or any air quality 

regulation or requirement. 

5. The toner shall be stored in containers with proper fire precautions observed. 

6. The toner shall be handled and transferred in such a manner as to minimize fugitive dust 

emissions. 

7. PSNH shall retain on-site the following information: 

a) Name and address of the company providing the toner; 

b) Amount of toner combusted; and 

c) RTAP compliance demonstration. 

8. When a new toner is combusted, PSNH shall notify DES in the semi-annual reporting. 

9. PSNH shall conduct an RTAP evaluation to determine compliance for each new toner and 

retain it along with a copy of the Material Safety Data Sheet (MSDS) on-site for inspection 

by DES, upon request. 
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VIII. Applicable Requirements

A. State-only Enforceable Operational and Emission Limitations 

The Permittee shall be subject to the state-only operational and emission limitations identified in 

Table 4 below. 

Table 4 – State-Only Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

1. Env-A 1403 All devices 

subject to 

RSA 125-I 

and Env-A 

1400 

All 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) All devices 

subject to 

RSA 125-I 

and Env-A 

1400 

Documentation for the demonstration of compliance shall be retained at 

the facility and shall be made available to DES for inspection upon 

request. 

3. Env-A 1404.01 All 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 All devices 

subject to 

RSA 125-I 

and Env-A 

1400 

The owner of any device or process subject to RSA 125-I and Env-A 

1400 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 subject to RSA 125-I and Env-A 1400 shall provide 

documentation of compliance with the AAL to DES. 

5. Env-A 1605.01 

Sulfur Content for 

Gaseous Fuels6

NT1 The sulfur content of gaseous fuels shall not exceed 15 grains of sulfur 

per 100 cubic feet of gas at standard temperature and pressure. 

 

B. Federally Enforceable Operational and Emission Limitations 

1. The Permittee shall be subject to the emission limitations summarized in Table 5 below for 

the listed fuel burning devices. 

 

6

 Env-A 1605 contains the most current requirement for the sulfur content of gaseous fuels. Env-A 1605 is state enforceable only 

because it is not included in New Hampshire’s State Implementation Plan (SIP). 40 CFR 52.1520 contains the New Hampshire rules 

that have been approved by EPA and adopted as part of the SIP. Env-A 402.03, effective on December 27, 1990, lists the federally 

enforceable sulfur limit for gaseous fuels because it was adopted as part of the SIP on September 14, 1992. Upon approval by EPA 

and adoption into New Hampshire’s SIP, Env-A 1605 will supercede Env-A 402.03, which will expire. 
 PSNH Newington Page 14 

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Table 5 – Summary of Emission Limitations 

Item 

No. 

Pollutant NT1 NTAB1 NTAB2 

1. SO2 Emissions 

Cap for 

Schiller 

Station, 

Merrimack 

Station and 

Newington 

Station 

combined 

55,150 tons per 

calendar year 

NA NA 

2. NOx 0.35 lb/MMBtu 

based on a 24-hour 

calendar day 

average with oil7

; 

0.25 lb/MMBtu 

based on a 24-hour 

calendar day 

average with 

oil/gas 

0.20 lb/MMBtu 

based on a 24-hour 

calendar day 

average; 50 tons 

per consecutive 

12-month period 

0.20 lb/MMBtu 

based on a 24-hour 

calendar day 

average; 50 tons 

per consecutive 

12-month period 

3. CO 0.231 lb/MMBtu 

based on a 24-hour 

calendar day 

average; 2915 tons 

per consecutive 

12-month period 

NA NA 

4. TSP 0.22 lb/MMBtu 0.41 lb/MMBtu 0.41 lb/MMBtu 

5. Opacity 40% for any 

continuous 6-

minute period 

40% for any 

continuous 6-

minute period 

40% for any 

continuous 6-

minute period 

2. The Permittee shall be subject to the federally enforceable operational and emission 

limitations identified in Table 6 below: 

Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

1. Env-A 

1211.03(c)(3)(c) 

NOx RACT for 

Utility Boilers 

NT1 A) When firing oil, the Permittee shall be limited to 0.35 lb NOx/MMBtu, 

based on a 24-hour calendar day average8

. 

B) When firing gas or any combination of oil and gas, the Permittee shall 

be limited to 0.25 lb NOx/MMBtu heat input based on a 24-hour 

calendar day average. 

C) If both a combination of gas and oil and exclusively oil are burned for 

separate periods within the same 24-hour calendar day, the applicable 

emission limit shall be a prorated value using the emission limits 

specified in Conditions B and C above and the actual hour that each 

 

7

 Note that 0.35 lb/MMBtu based on a 24-hour calendar day average is equivalent to 4,416.1 tons per consecutive 12-month period based on 

an annual heat input of 25,235,000 MMBtu and 0.35 lb/MMBtu. 

8

 Note that 0.35 lb/MMBtu based on a 24-hour calendar day average is equivalent to 4,416.1 tons per consecutive 12-month period based on 

an annual heat input of 25,235,000 MMBtu and 0.35 lb/MMBtu 
 PSNH Newington Page 15 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

fuel type is burned as indicated in the following equation: 

og o

og o

t t

t lb MMBtu t lb MMBtu

AEL = 

+

( * 25.0 / ) + ( * 35.0 / )

Where: 

AEL=allowable NOx emission limit (in lb/MMBtu) 

tog=Number of hours within 24-hour calendar day when burning any 

combination of gas and oil 

to=Number of hours within 24-hour calendar day when burning exclusively 

oil 

2. State Permit to 

Operate No. PO-B1030 and Env-A 

1604.01(c)(2) Fuel 

Specifications for 

No. 6 Fuel Oil and 

Crude Oil 

NT1 The sulfur content of No. 6 fuel oil and crude oil shall not exceed 2.00 

percent sulfur by weight. 

3. State Permits to 

Operate Nos. POB-1030, PO-B1031, PO-B-1032 

and Env-A 

1604.01(a) Fuel 

Specifications for 

No. 2 Fuel Oil 

NT1, 

NTAB1, 

NTAB2, 

NTEG 

The sulfur content of No. 2 fuel oil shall not exceed 0.40 percent by weight. 

 

4. 40 CFR 52.15209

Sulfur Content for 

Gaseous Fuels 

NT1, 

NTAB1, 

NTAB2 

The sulfur content of gaseous fuels shall not exceed 5 grains of sulfur per 

100 cubic feet of gas at standard temperature and pressure. 

5. State Permit to 

Operate No. PO-B1030 

NT1 PSNH shall use No. 2 fuel oil or natural gas to start-up the boiler. 

6. State Permit to 

Operate No. PO-B1030 Maximum 

Gross Heat Input 

NT1 A) The maximum operating rate of this electric generating unit is limited to 

4,350 MMBtu/hr (nameplate rating)10 gross heat input of crude oil or 

No. 6 fuel oil at not more than 2.0% sulfur content by weight, No. 2 fuel 

oil at not more than 0.4% sulfur content by weight or natural gas or any 

combination thereof. 

 

9

 40 CFR 52.1520 contains the New Hampshire rules that have been approved by EPA and adopted as part of the State Implementation 

Plan (SIP). Env-A 402.03, effective on December 27, 1990, contained the sulfur limit for gaseous fuels was adopted as part of the SIP 

on September 14, 1992. Env-A 402.03 and is still considered to be federally enforceable until such time as the SIP is amended and 

approved by the EPA. This requirement will expire at such time that Env-A 1605, the amended rule containing the sulfur content limit 

for gaseous fuels, is approved by EPA and adopted as part of the SIP. 

10 The heat input rating of 4,350 MMBtu/hr was calculated based upon the nameplate rating of NT1, fuel flow to the boiler, and Btu 

analysis of the fuel. The CEMS calculates and records the heat input on a minute-by-minute basis according to the procedures in 40 

CFR 75. The calculated heat input from the CEMS is based upon the volumetric flow of the stack gases, the CO2 concentration, and a 

carbon-based F factor—a default factor provided in 40 CFR Part 75. The calculated heat input rate from the CEMS is not based on 

fuel flow. 
 PSNH Newington Page 16 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

B) In accordance with NSR avoidance for CO, the maximum operating rate 

shall not exceed 25,235,000 MMBtu total gross heat input during any 

consecutive 12-month period. Upon written approval from DES, PSNH 

may adjust the maximum operating rate provided that PSNH would not 

exceed the emission limitations established in the permit. 

7. State Permit to 

Operate No. PO-B1030 and Env-A 

404.01 State Acid 

Deposition Control 

Program 

NT1 The total SO2 emissions from Newington Station’s Unit No. 1 (NT1), 

Schiller Station, and Merrimack Station shall not exceed 55,150 tons per 

calendar year. 

8. State Permits to 

Operate Nos. POB-1030 and Env-A 

2002.01 and 

2002.04 (b) Visible 

Emission Standard 

for Fuel Burning 

Devices 

NT1 During normal operation, the average opacity shall not exceed 40 percent 

for any continuous 6-minute period. The 6-minute time blocks shall be 

established to provide for ten 6-minute blocks per calendar hour. The first 

6-minute time block in any calendar hour in excess of the opacity standard 

will not be considered an excess emission. Any subsequent time block in 

the same calendar hour in exceedance of the opacity standard shall be 

considered an excess emission. To be considered an excess emission, the 

subsequent time block in the same calendar hour in excess of the opacity 

standard does not have to be consecutive in occurrence with the first 

exceedance. The average opacity may exceed 40 percent for a nonoverlapping set or sets of time up to 60 minutes in any 8-hour period during 

startup, shutdown, malfunction, soot blowing, grate cleaning, and cleaning 

of fires. 

9. State Permits to 

Operate Nos. POB-1031, PO-B1032 and Env-A 

2002.01 and 

2002.04 (c) Visible 

Emission Standard 

for Fuel Burning 

Devices 

NTAB1, 

NTAB2 

The average opacity shall not exceed 40 percent for any continuous 6-

minute period. The average opacity may exceed 40 percent for one period 

of 6 continuous minutes in any 60 minute period during startup, shutdown, 

malfunction, soot blowing, grate cleaning, and cleaning of fires. 

10. State Permit to 

Operate No. PO-B1030, and Env-A 

2002.06(c)(2) 

Particulate 

Emission 

Standards 

NT1 PSNH shall not cause or allow emissions of particulate matter in excess of 

the following equation at the utility boiler: 

.0 166 .0 880 *− E = I

Where: 

E=maximum allowable particulate matter emission rate in lb/MMBtu = 0.22 

lb/MMBtu 

I=maximum gross heat input rate in MMBtu/hr = 4,350 MMBtu/hr 

This limitation is independent of fuel type and applies at all times, including 

during flyash reinjection. 

11. State Permit to 

Operate PO-B1030 

NT1 A) PSNH shall not exceed a CO emission rate of 0.231 lb/MMBtu for any 

24-hour calendar day average as calculated by the CEMs. This 

limitation is independent of fuel type and applies at all times. 
 PSNH Newington Page 17 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

B) PSNH shall not exceed an annual CO emission rate of 2,915 tons per 

consecutive 12-month period based upon 0.231 lb/MMBtu and the New 

Source Review limited maximum annual operating rate of 25,235,000 

MMBtu/year. As long as the daily and annual CO emission rates are 

not exceeded, the maximum annual operating rate is not a permit 

limitation. 

12. State Permit to 

Operate No. PO-B1030 

ESP Operating 

Requirements 

NT1 A) PSNH shall maintain and operate the ESP system for the control of 

particulate matter, in accordance with the manufacturer’s 

recommendations. 

B) The ESP unit shall be operational at all times that the facility is in 

operation above 120 MW on any combination of oil and oil/gas. The 

ESP will not normally be energized when the unit is burning 100 

percent natural gas. 

C) The inlet temperature of the ESP as measured at the outlet of the boiler 

shall not exceed 785°F. 

D) The secondary voltage of the transformer rectifier sets (TR sets) is 

automatically controlled to operate between a maximum of 45 KVDC 

and a minimum of 7500 VDC based on the dust loading rate, spark rate, 

and opacity. 

E) PSNH shall optimize the ESP based on the opacity baseline for high 

load service. 

F) PSNH shall track the fields out of service. 

G) PSNH shall continuously operate and maintain the ESP system to 

minimize particulate matter emissions, to meet permit conditions, and to 

maintain compliance with Env-A 2000. The operation and maintenance 

shall include the normal procedures for scheduled checking and 

cleaning of the hoppers and transport lines. All maintenance procedures 

performed and corrective actions taken on the ESP system shall be 

recorded. The records shall be maintained at the facility and shall be 

made available for review at the request of the DES. All deviations 

from the operation criteria described above and the corrective actions 

taken shall be recorded in the work management system or logbook. 

13. State Permit to 

Operate PO-B1030 

New Source 

Review Avoidance 

NT1 A) PSNH avoided NSR when adding the natural gas firing capabilities on 

the basis that the emissions would not increase. 

B) If an emissions increase occurs in the maximum 24-hour calendar day 

average emission rate (calculated in lb/MMBtu) of any pollutant as 

determined in accordance with 40 CFR 60.14 and by DES when 

burning natural gas, then the natural gas conversion shall be subject to 

NSPS. 

C) If an emissions increase occurs in the actual annual emissions of any 

pollutant as determined in accordance with 40 CFR 51.165, 40 CFR 

52.21 or by DES, then the natural gas conversion shall be subject to 

NSR. 

D) PSNH shall not exceed the 24-hour calendar day average emission rates 

of CO (0.231 lb/MMBtu) and NOx (0.25 lb/MMBtu for oil/gas and 

0.35 for oil) as specified above. The maximum annual operating rate of 

25,235,000 MMBtu/year was used to calculate the applicable CO 

emission permit limits, which will be enforced through the annual CO 
 PSNH Newington Page 18 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

emission limit by DES to protect the annual baseline emission limits for 

CO. The maximum annual operating rate referred to herein may be 

adjusted by PSNH provided that the resulting emissions will not 

contribute significantly to or cause a violation of any applicable 

NAAQS, or a violation of any applicable PSD increment, or a violation 

of the NH State Implementation Plan, or a violation of any condition 

contained in a permit issued pursuant to regulations approved or 

promulgated under the CAA. Regardless of the maximum annual 

operating rate, the emission limitations established in this permit shall 

not be exceeded. 

E) Any adjustments, requested by PSNH, to the maximum NOx and CO 

emission limits and the maximum operating rate referred to herein will 

be made only after DES’ review of applicable supporting data. Any 

adjustments made shall not result in an increase of emissions. 

Adjustments shall not be made until PSNH has received written 

approval from DES. 

14. State Permit to 

Operate PO-B1030 

NT1 PSNH shall follow standard operating procedures for cold boiler start-up 

and boiler repair practices to ensure compliance with opacity standards. 

15. 40 CFR 72, 73, 

and 77 Acid Rain 

Provisions 

NT1 PSNH shall comply with the applicable Federal Acid Rain Program 

provisions. 

16. Env-A 1211.12 

NOx RACT for 

Auxiliary Boilers 

NTAB1, 

NTAB2 

A) Each auxiliary boiler shall be limited to a NOx RACT emission limit of 

0.20 lb/MMBtu based on a 24-hour calendar day average, regardless of 

the type of fuel burned. 

B) The emissions from all auxiliary boilers shall be included in the 

calculation of both the actual and theoretical potential emissions from 

the stationary source. 

17. State Permits to 

Operate Nos. POB-1031, PO-B1032 Maximum 

Fuel Consumption 

NTAB1, 

NTAB2 

A) Maximum fuel consumption rate of No. 2 fuel oil for each device shall 

not exceed 3.57 million gallons during any consecutive 12-month 

period.11 

B) This fuel consumption limitation is to limit the NOx emissions to less 

than 50 tons during any consecutive 12-month period. 

18. Env-A 2002.06 

(c)(2) Particulate 

Emission 

Standards 

NTAB1, 

NTAB2 

PSNH shall not cause or allow emissions of particulate matter in excess of 

the following equation at each of the auxiliary boilers: 

.0 166 .0 880 *− E = I

Where: 

E=maximum allowable particulate matter emission rate in lb/MMBtu = 0.41 

lb/MMBtu 

I=maximum gross heat input rate in MMBtu/hr = 99.4 MMBtu/hr 

19. 40 CFR 63 Subpart 

YYYY MACT for 

Stationary 

Combustion 

NTEG The MACT is applicable to the combustion turbine, but no emission 

limitations, operating requirements or monitoring, recordkeeping, or 

reporting requirements are specified for existing units. 

 

11 The heating value of No. 2 fuel oil is assumed to be 140,000 BTU/gallon. The fuel consumption limits may vary based on the actual 

heat content of the fuel burned. 
 PSNH Newington Page 19 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

Turbines 

20. State Permit to 

Operate No. PO-B1842 Env-A 

1211.01 (j) and 

1211.11 NOx 

RACT for 

Emergency 

Generators 

NTEG A) Each emergency generator shall be limited to less than 500 hours of 

operation during any consecutive 12-month period. 

B) The combined theoretical potential NOx emissions from all emergency 

generators combined are limited to less than 25 tons for any consecutive 

12-month period. 

C) The NOx RACT requirements of Env-A 1211.11 shall apply if neither 

the hourly limitation nor the NOx emission limitation is met. 

D) The emissions from emergency generators shall be included in the 

actual and theoretical potential emissions from the facility. 

21. State Permit to 

Operate No. PO-B1842 and Env-A 

2002.02 and 

2002.04(c) Visible 

Emission Standard 

for Fuel Burning 

Devices 

NTEG The average opacity shall not exceed 20 percent for any continuous 6-

minute period. The average opacity may exceed 20 percent for one period 

of 6 continuous minutes in any 60 minute period during startup, shutdown, 

malfunction, soot blowing, grate cleaning, and cleaning of fires. 

22. Env-A 2002.07 

(c)(1) Particulate 

Emission Rate 

NTEG The TSP emission rate shall not exceed 0.60 lb/MMBtu based on a 24-hour 

calendar day.12 

23. Env-A 1002 

Fugitive Dust 

Facility wide The Permittee shall take precautions, such as wetting, covering, shielding or 

vacuuming, to prevent, abate, and control fugitive dust emissions during any 

activity, which might create fugitive dust. Such activities include bulk 

hauling activities, including the transportation and transfer of mineral 

material over public roads and maintenance activities, including sweeping, 

vacuuming, or other activity involved with the upkeep of roads or parking 

lots. 

24. 40 CFR 68 and 

1990 CAA Section 

112(r)(1) 

Accidental Release 

Program 

Requirements 

Facility wide The Permittee maintains no quantities of regulated substances above the 

threshold quantities established by the EPA under 40 CFR 68.130. 

Administrative controls will be established by the Permittee in order to 

ensure that inventories of regulated substances are maintained below the 

specified threshold quantities. The facility is subject to the Purpose and 

General Duty clause of the 1990 Clean Air Act, Section 112(r)(1). General 

Duty includes the following responsibilities: 

(A) Identify potential hazards that may result from such releases using 

appropriate hazard assessment techniques; 

(B) Design and maintain a safe facility; 

(C) Take steps necessary to prevent releases; and 

(D) Minimize the consequences of accidental releases that do occur. 

If, in the future, the Permittee wishes to store quantities of regulated 

substances above the threshold levels, a risk management plan shall be 

submitted to the Part 68 implementing agency prior to exceeding threshold 

quantity levels in a timely manner. 

 

12 PSNH shall demonstrate compliance with this requirement by using an EPA-approved emission factor and EPA/DES approved heat 

input content (Btu/gallon). This calculation shall be maintained on file at the facility. 
 PSNH Newington Page 20 

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Table 6 – Federally Enforceable Operational and Emission Limitations 

Item 

No. 

Regulatory Cite Applicable 

Emission 

Unit 

Applicable Requirement 

25. 40 CFR 61 Subpart 

M, Env-A 

504.01(e) and EnvA 1800 

Asbestos 

Management and 

Control 

Facility wide PSNH shall comply with the asbestos requirements of Env-A 1800 and 40 

CFR 61.145 during demolition and/or renovation. 

C. Annual SO2 Allowance Programs (40 CFR 72, 40 CFR 73, Env-A 611.07, and Env-A 2900) 

1. SO2 Allowance Allocation 

a) In accordance with 40 CFR Part 73, SO2 allowances pursuant to the Federal Acid Rain 

Program for this facility are allocated as indicated in the following table: 

Table 7 – SO2 Allowance Allocation (tons) 

2003 2004 2005 2006 2007 2008 2009 2010 

NT1 11,660 11,660 11,660 11,660 11,660 11,660 11,660 10,613 

b) Pursuant to Env-A 2906.02 [State enforceable only], Allocation of SO2 Allowances, for 

2007 and subsequent years, PSNH’s Schiller, Merrimack and Newington (NT1) Stations 

shall transfer the SO2 Allowances allocated pursuant to the Federal Acid Rain Program to 

DES, and DES shall transfer SO2 allowances (7,289 tons) calculated pursuant to Env-A 

2900 plus any potential bonus allowances calculated pursuant to Env-A 2906.07, Bonus 

Allocation of SO2 Allowances back to PSNH’s Schiller, Merrimack, and Newington 

stations. The amount of SO2 Allowances allocated to PSNH Newington shall be 

determined according the methodology in Env-A 2906.05, Allowance Allocation 

Methodology. 

2. Compliance 

a) Pursuant to 40 CFR 73.35, the Permittee shall comply with the SO2 emission limitation 

requirements. 

b) At the end of each calendar year, the Permittee shall hold sufficient SO2 allowances 

equivalent to the SO2 emissions during that calendar year. 
 PSNH Newington Page 21 

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3. General Provisions 

Pursuant to Env-A 611.07 and Env-A 2900, SO2 allowances lawfully held or acquired by the 

Permittee shall be governed by the following: 

a) Emissions from the affected units shall not exceed any SO2 allowances held by the 

affected unit; 

b) The number of SO2 allowances held by the Permittee shall not be limited; 

c) The Permittee shall not use SO2 allowances to avoid compliance with any other 

applicable requirement of either state or federal rules or of the provisions of the Clean Air 

Act; and 

d) Any SO2 allowances held by the Permittee shall be accounted for according to the 

procedures established in the applicable provisions of 40 CFR 72, 40 CFR 73, and 40 

CFR 76. 

4. Excess Emissions 

Pursuant to 40 CFR 72.9(e), if the Permittee has excess emissions, the Permittee shall submit 

a proposed offset plan as required under 40 CFR 77 and pay the penalty and any interest 

without demand pursuant to 40 CFR 77. Additional penalties may apply pursuant to Env-A 

2900. See Condition VIII. F.8. 

5. Allowance Transfer 

The Permittee shall transfer allowances according to the procedures in 40 CFR 73.50. 

D. Ozone Season NOx Budget Trading Program (Env-A 3200) 

1. NOx Allowance Allocation 

a) Pursuant to Env-A 3207.03, Allocation of Allowances, the amount of NOx allowances 

allocated to PSNH shall be as set forth in the Table 8 below for the 2003, 2004, and 2005 

control periods (ozone seasons of May 1 through September 30): 

 
 PSNH Newington Page 22 

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Table 8 – NOx Allowance Allocation for the 

Ozone Season (tons) 

Emission 

Unit 

2003 2004 2005 

NT1 579 507 434 

2. The NOx allowances shall be allocated to PSNH for the 2006 control period (ozone season) 

and subsequent control periods according to the methodology in Env-A 3207.04, Future 

Allowance Allocation Methodology. 

3. Ozone Season NOx Emissions Cap 

a) Pursuant to Env-A 3200, PSNH shall not emit NOx emissions during any control period 

in excess of the amount of NOx allowances held in PSNH’s NATS compliance account 

for that control period as of the allowance transfer deadline of November 30. 

b) Pursuant to Env-A 3200, PSNH may obtain additional NOx allowances to comply with 

the NOx Budget Program. 

4. Allowance Transfer and Use 

a) Pursuant to Env-A 3209.01, Marketable Emissions Authorization, an allowance shall be a 

marketable emissions authorization that may be bought, sold, or traded at any time during 

any year, not just the current year. 

b) Pursuant to Env-A 3209.02, Limited Authorization, an allowance shall only be used for 

compliance with the NOx Budget Program in a designated compliance year by being in a 

compliance account as of the allowance transfer deadline of November 30, or by being 

transferred into the compliance account by an allowance transfer submitted by the 

allowance transfer deadline. 

c) PSNH shall comply with the NOx allowance transfer and use provisions pursuant to EnvA 3209, Allowance Transfer and Use. 

d) Pursuant to Env-A 3209.09, Price Disclosure, subject to a claim of confidentiality in 

accordance with Env-A 103, PSNH shall make available to any person, all information 

regarding transaction cost and allowance price. 

5. Allowance Banking 

a) Pursuant to Env-A 3210.01, Retention of Unused Allowances, the banking of allowances 

shall be permitted to allow the retention of unused allowances from one year to a future 

year in either a compliance account, an overdraft account, or a general account. 

b) Pursuant to Env-A 3210.02, Account Designation, unless otherwise permitted pursuant to 

Env-A 3210.04, Early Reduction Allowances, unused allowances as of the end of the 

allowance transfer deadline shall be retained in the compliance, overdraft, or general 

account and designated as banked allowances after the NATS administrator has made all 
 PSNH Newington Page 23 

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deductions for a given control period from the compliance account or overdraft account 

pursuant to Env-A 3215, End-of-Season Reconciliation.

c) PSNH shall comply with the NOx allowance banking provisions pursuant to Env-A 3210, 

Allowance Banking. 

6. End-of-Season Reconciliation 

a) Pursuant to Env-A 3206.01, Limited Authorization, PSNH shall, no later than November 

30 of each calendar year, hold respective a quantity of NOx allowances in PSNH 

Newington’s current year NATS account that is equal to or greater than the total NOx

emitted from PSNH Newington during the period May 1 through September 30 of the 

subject year. 

b) PSNH shall determine compliance and reconcile allowances by November 30 of each 

year for the control period of that year pursuant to Env-A 3215. 

7. Authorized Account Representative (Env-A 3211.04) 

a) Only the AAR or alternate AAR shall request transfers of allowances in a NATS account. 

b) The AAR or alternate AAR shall be responsible for all transactions and reports submitted 

to the NATS. 

c) The alternative AAR shall have the same authority as the primary representative, 

however, all correspondence from the NATS administrator shall be directed to the 

primary AAR. 

d) Pursuant to Env-A 3211.05 (f), PSNH shall replace an AAR by submitting a revised 

Account Certificate of Representation to the NATS administrator along with the 

information contained in Env-A 3211.05(b) and (c) and the name of the AAR who is 

being replaced. 

8. Conversion of Allowances to DERs 

Pursuant to Env-A 3207.05, PSNH Newington may convert unused allowances to DERs in 

accordance with Env-A 3206.02(e) for use as NSR offsets during the ozone season and the 

procedures for DER generation pursuant to Env-A 3103. Upon conversion, PSNH 

Newington shall surrender those converted allowances as if they had been used for actual 

emissions. Under no other circumstances shall unused allowances be converted to, or used 

as, DERs or ERCs. 

9. Prohibition on Property Rights (Env-A 3207.07) 

a) Neither an allowance nor any future allocations, which are subject to modification by 

DES, shall constitute a security or other form of property. 

b) An allowance shall not be used prior to the control period for which the allowance is 

allocated. 
 PSNH Newington Page 24 

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10. Excess Emissions and Enforcement Provisions (Env-A 3217) 

a) If emissions exceed the allowances held by PSNH Newington by the allowance transfer 

deadline (November 30), the NATS administrator shall automatically deduct three tons of 

allowances from the next control period for every ton of excess emissions from PSNH 

Newington compliance account or overdraft account. 

b) In accordance with RSA 125-J:4-a, for purposes of enforcement of the NOx Budget 

Program, in determining the number of days of violation, any excess emissions for the 

control period shall presume that each day in the control period of 153 days, constitutes a 

day in violation unless PSNH Newington can demonstrate, through use of verifiable 

emissions data that a lesser number of days should be considered. In addition, each ton of 

excess emissions shall constitute a separate violation. 

E. Non-Ozone Season NOx Allowance Program ( NOx RACT Order No. ARD-98-001) 

Pursuant to NOx RACT Order No. ARD-98-001, PSNH’s Schiller, Merrimack, and Newington 

stations shall comply with a NOx emissions cap of 8208 tons for the non-ozone season beginning 

on October 1 and ending on April 30. Ozone season DERs and non-ozone season DERS may be 

used to comply with this non-ozone season limit. Previously generated (1995 through 1998) 

DERs may be used to comply with this emissions cap. DERs may be generated from PSNH’s 

Newington and Schiller Stations, in accordance with the protocols submitted by PSNH to comply 

with this emissions cap. 

F. Multiple Pollutant Annual Budget Trading and Banking Program (Env-A 2900) [State 

Enforceable Only] 

1. SO2 Allowance Allocation 

Pursuant to Env-A 2900, Multiple Pollutant Annual Budget Trading and Banking Program, 

and subsequent revisions, DES shall allocate SO2 Allowances to PSNH Newington according 

to the methodology in Env-A 2906.05, Allowance Allocation Methodology for 2007 and 

subsequent years. 

2. NOx Allowance Allocation 

a) Pursuant to Env-A 2900, Multiple Pollutant Annual Budget Trading and Banking 

Program, and subsequent revisions, DES shall allocate NOx Allowances to PSNH 

Newington according to the methodology in Env-A 2906.05, Allowance Allocation 

Methodology for 2007 and subsequent years. 

b) Pursuant to Env-A 2900, Multiple Pollutant Annual Budget Trading and Banking 

Program, and subsequent revisions, for 2007 and subsequent years, DES shall calculate 

the difference between the annual NOx budget (no more than 3,644 tons) and the ozone 

season NOx allowances allocated pursuant to Env-A 3200. 
 PSNH Newington Page 25 

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c) Pursuant to Env-A 2900, Multiple Pollutant Annual Budget Trading and Banking 

Program, and subsequent revisions, for 2007 and subsequent years, DES shall allocate 

annual NOx allowances equivalent to the difference between the annual NOx budget and 

the ozone season NOx allowances to PSNH’s Schiller, Merrimack, and Newington 

stations. 

3. CO2 Allowance Allocation 

Pursuant to Env-A 2900, Multiple Pollutant Annual Budget Trading and Banking Program, 

and subsequent revisions, DES shall allocate CO2 Allowances to PSNH Newington according 

to the methodology in Env-A 2906.05, Allowance Allocation Methodology for 2007 and 

subsequent years. 

4. Allowance Transfer and Use 

a) Pursuant to Env-A 2907.01, Marketable Emissions Authorization, an allowance shall be a 

marketable emissions authorization that may be bought, sold, or traded at any time during 

any year, not just the current year. 

b) Pursuant to Env-A 2907.02, Limited Authorization, an allowance shall only be used for 

compliance with the Multiple Pollutant Annual Budget Trading and Banking Program in 

a designated compliance year by being in a compliance or overdraft account as of the 

allowance transfer deadline, or by being transferred into the compliance account by an 

allowance transfer submitted by the allowance transfer deadline. 

c) PSNH shall comply with the allowance transfer and use provisions pursuant to Env-A 

2907, Allowance Transfer and Use, and Env-A 2909, Allowance Tracking System. 

d) Pursuant to Env-A 2907.08, Price Disclosure, subject to a claim of confidentiality in 

accordance with Env-A 103, PSNH shall make available to any person, all information 

regarding transaction cost and allowance price. 

e) Pursuant to Env-A 2907.09, Use of Allowances by Utilities, and RSA 125-J:5, X, the use 

of allowances by a utility as defined in RSA 362:2, shall be subject to such additional 

conditions as ordered pursuant to applicable law by the PUC. 

5. Allowance Banking 

a) Pursuant to Env-A 2908.01, Retention of Unused Allowances, the banking of allowances 

shall be permitted to allow the retention of unused allowances from one year to a future 

year in either a compliance account, an overdraft account, or a general account. 

b) Pursuant to Env-A 2908.02, Account Designation, unless otherwise permitted pursuant to 

Env-A 2909.03, General Accounts, unused allowances as of the end of the allowance 

transfer deadline shall be retained in the compliance, overdraft, or general account and 

designated as banked allowances after the ATS administrator has made all deductions for 

a given year from the compliance account or overdraft account pursuant to Env-A 2913, 

Compliance Certification.
 PSNH Newington Page 26 

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c) Pursuant to Env-A 2908.03, Bonus Early Allowances, bonus early allowances shall be 

eligible for a one-time conversion to allowances in 2007. Bonus early allowances that are 

converted to allowances shall not be used as VERs, ERCs, or DERs. 

6. Authorized Account Representative (Env-A 2909.04) 

a) Only the AAR or alternate AAR shall request transfers of allowances in an ATS account. 

b) The AAR or alternate AAR shall be responsible for all transactions and reports submitted 

to the ATS. 

c) The alternative AAR shall have the same authority as the primary representative, 

however, all correspondence from the ATS administrator shall be directed to the primary 

AAR. 

d) Pursuant to Env-A 2909.05 (f), PSNH shall replace an AAR by submitting a revised 

Account Certificate of Representation to the ATS administrator along with the 

information contained in Env-A 2909.05(b) and (c) and the name of the AAR who is 

being replaced. 

7. End-of-Season Reconciliation 

a) Pursuant to Env-A 2904.01, Limited Authorization, PSNH shall, no later than January 30 

of each calendar year, hold respective quantities of SO2, NOx, and CO2 in the PSNH 

Newington’s respective ATS accounts equal to or greater than the respective total SO2, 

NOx, and CO2 emitted from PSNH Newington during the previous year. 

b) Pursuant to Env-A 2912.01, Determination of Compliance, monitored emissions data as 

reported by PSNH to the ETS administrator, and as adjusted by the administrator to be in 

accordance with Env-A 2910, Emissions Monitoring, combined with allowance 

allocations and transfers recorded in the ATS, shall provide the basis for a determination 

of compliance. 

c) PSNH shall determine compliance and reconcile allowances by January 30 of each year 

beginning in 2008 pursuant to Env-A 2913. 

d) Pursuant to Env-A 2912.02, Request for Deduction of Allowances, no later than January 

30, the AAR shall request the ATS administrator to deduct previous year allowances from 

the compliance account or overdraft account equivalent to the number of available 

allowances to cover the emissions during the previous year. The AAR shall identify the 

compliance account or overdraft account from which the deductions shall be made and 

shall identify the serial number of the allowances to be deducted. If the AAR does not 

specify a serial number, allowances useable for that compliance year shall be deducted in 

the order of their arrival into PSNH Newington’s account, with allocated allowances 

being deducted first, followed by the deduction of transferred allowances. 

e) Pursuant to Env-A 2912.04, Procurement of Additional Allowances, if the emissions of 

PSNH Newington in the previous year exceed the allowances in PSNH Newington’s 

compliance account and overdraft account, PSNH Newington shall obtain additional 
 PSNH Newington Page 27 

 TV-OP-054 

allowances by January 30 so that the total number of allowances in PSNH Newington’s 

compliance account and overdraft account, including allowance transfers properly 

submitted to the ATS administrator by January 30, equals or exceeds the previous year 

annual emissions rounded to the nearest whole ton. 

8. Excess Emissions and Enforcement Provisions (Env-A 2914) 

a) If emissions exceed the allowances held by PSNH Newington by the allowance transfer 

deadline (January 30), the Allowance Tracking System administrator shall automatically 

deduct three tons of allowances for every ton of excess emissions. 

b) In accordance with RSA 125-O:7, for purposes of enforcement of the Multiple Pollutant 

Annual Budget Trading and Banking Program, in determining the number of days of 

violation, any excess emissions for the year shall create a presumption that each day in 

the year of 365 days, constitutes a day in violation unless PSNH Newington can 

demonstrate, through use of verifiable emissions data that a lesser number of days should 

be considered. In addition, each ton of excess emissions shall constitute a separate 

violation. 

9. Conversion of Allowances to DERs or VERs 

a) Pursuant to Env-A 2904.01 (d), allowances shall not be considered offsets, although NOx 

allowances which are not used to satisfy the requirements of Env-A 2900, and which are 

not banked, may be converted to non-ozone season NOx DERs in accordance with Env-A 

3100. 

b) Pursuant to Env-A 2904.02, Conversion of Allowances to DERs or VERs, if PSNH 

converts unused NOx allowances to NOx DERs in accordance with Env-A 2904.01(d) 

and the procedures for DER generation pursuant to Env-A 3103, or converts unused CO2 

allowances to VERs in accordance with Env-A 3800, PSNH shall surrender those 

converted allowances as if they had been used for actual emissions. 

10. Prohibition on Property Rights (Env-A 2904.04) 

a) Neither an allowance nor any future allocations, which are subject to modification by 

DES, shall constitute a security or other form of property. 

b) An allowance shall not be used prior to the year for which the allowance is allocated. 

G. Discrete Emission Reduction Trading Program (Env-A 3100) 

In accordance with Env-A 3100, NOx RACT Orders Nos. ARD-97-001 and ARD-98-001, and 

the Notices of Simultaneous Generation and Use of DERs originally submitted on April 10, 

1998, and annually thereafter upon entry of the DERs into the registry by DES, PSNH 

Newington shall be allowed to bank DERs for PSNH Newington’s own future use. 
 PSNH Newington Page 28 

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H. Monitoring/Testing Requirements 

The Permittee is subject to the monitoring/testing requirements as contained in Table 9 below: 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

1. NT1 NOx 

Emissions 

For NT1, PSNH shall install, certify, operate 

and maintain, a NOx-diluent continuous 

emission monitoring system (consisting of a 

NOx pollutant concentration monitor and an 

O2 or CO2 diluent gas monitor) with an 

automated data acquisition and handling 

system for measuring and recording NOx 

concentration (in ppm) averaged on an hourly 

and 24-hour calendar day basis, O2 or CO2

concentration (in percent O2 or CO2) and NOx 

mass emission rate (in lb/MMBtu) averaged on 

an hourly, 24-hour calendar day, and annual 

basis for each unit. PSNH shall account for 

total NOx emissions, both NO and NO2, either 

by monitoring for both NO and NO2 or by 

monitoring for NO only and adjusting the 

emissions data to account for NO2. PSNH 

shall measure and record NOx emissions in 

lb/hr averaged for one-hour and a 24-hour 

calendar day, and tons/consecutive 12-month 

period. PSNH shall calculate hourly, 

quarterly, and annual NOx emission rates (in 

lb/mmBtu) by combining the NOx 

concentration (in ppm), diluent concentration 

(in percent CO2), and percent moisture 

according to the procedures in 40 CFR 75 

Appendix F. 

Continuously Env-A 808.02 

(a) (new) and 

40 CFR 

75.10(a)(2), 

75.12, and 

Env-A 

1211.03 (f) 

2. NT1 NOx Mass 

Emissions 

For NT1, PSNH shall calculate hourly NOx 

mass emissions (in lbs) by multiplying the 

hourly NOx emission rate (in lbs/mmBtu) by 

the hourly heat input rate (in mmBtu/hr) and 

the unit or stack operating time. PSNH shall 

also calculate quarterly and cumulative yearto-date NOx mass emissions and (in tons) by 

summing the hourly NOx mass emissions 

according to the procedures in 40 CFR 75 

Appendix F Section 8. 

Hourly, 

quarterly, and 

cumulative yearto-date 

40 CFR 75.71, 

and 75.72 and 

Env-A 3212 

and Env-A 

2910 

3. NT1 Ozone Season 

NOx Emission 

Rate and NOx 

Mass 

Emissions 

PSNH, when required, shall determine the 

ozone season NOx emission rate (in 

lb/MMBtu) by dividing ozone season NOx 

mass emissions (in lbs) by heat input. PSNH 

shall also calculate cumulative NOx mass 

emissions for the ozone season (in tons) by 

During the ozone 

season 

Env-A 

3212.01 and 

40 CFR 

75.75(b) and 

75.72 
 PSNH Newington Page 29 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

summing the hourly NOx mass emissions 

according to the procedures in 40 CFR 75 

Appendix F Section 8. 

4. NT1, 

NTAB1, 

NTAB2 

Sulfur Content 

of No. 2 Fuel 

Oil, No. 6 

Fuel Oil, and 

Crude Oil 

Fuel delivery tickets, other documentation 

from the fuel supplier or testing in accordance 

with appropriate ASTM test methods that 

certify the weight-percent of sulfur for each 

delivery of the No. 2 fuel oil, No. 6 fuel oil, 

and crude oil. 

Each delivery of 

fuel 

Env-A 806.02 

5. NT1 Sulfur Content 

of Natural Gas 

Documentation from fuel supplier or conduct 

testing to determine the sulfur content of 

natural gas. 

Upon request by 

DES and/or EPA 

Env-A 809.02 

(old) and EnvA 806.03 

(new) 

6. NT1 SO2 Emissions PSNH shall install, certify, operate and 

maintain, an SO2 CEMS automated data 

acquisition and handling system for measuring 

and recording SO2 concentration (in ppm) 

averaged on an hourly and 24-hour calendar 

day basis, volumetric gas flow (in scfh), and 

SO2 mass emissions (in lb/hr averaged over 

one hour and each 24-hour calendar day, and 

tons/consecutive 12-month period and 

tons/calendar year) for each unit. PSNH shall 

demonstrate compliance with the State Acid 

Rain Program emission caps by using the 

CEMS data. 

Continuously Env-A 808.02 

(a)(1) (new) 

and 40 CFR 

75.10 (a)(1) 

7. NT1 CO2

Emissions 

PSNH shall install, certify, operate and 

maintain, a CO2 CEMS automated data 

acquisition and handling system. PSNH shall 

measure and record CO2 emissions in lb/hr 

averaged over each 24-hour calendar day and 

CO2 concentration in percent averaged over 

each hour and over each 24-hour calendar day. 

 

Continuously 40 CFR 

75.10(a)(3), 

and State 

Permit to 

Operate No. 

PO-B-1030 

8. NT1 Stack 

volumetric 

flow rate 

PSNH shall install, certify, operate and 

maintain, a CEMS automated data acquisition 

and handling system to measure and record 

stack volumetric flow rate (in kscfm) averaged 

over each hour and over each 24-hour calendar 

day. 

Continuously 40 CFR 75, 

Env-A 

2910.02 

9. NT1 Heat Input 

Rate 

PSNH shall determine the heat input rate (in 

MMBtu/hr) to each unit for every hour or part 

of an hour any fuel is combusted following the 

procedures in 40 CFR 75 Appendix F. 

Hourly 40 CFR 

75.10(c) and 

Env-A 

2910.02 

10. NT1 Net Electrical 

Output 

PSNH shall monitor and/or calculate net 

electrical output. 

Annually Env-A 

2910.02 and 

40 CFR 75 

11. NT1 Ozone Season 

Heat Input 

To determine the number of NOx allowances 

allocated, PSNH shall calculate ozone season 

Hourly during 

ozone season 

Env-A 

3212.01 and 
 PSNH Newington Page 30 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

heat input by summing each unit’s hourly heat 

input determined according to the procedures 

in 40 CFR 75 for all hours in which the unit 

operated during the ozone season 

40 CFR 

75.75(a) 

12. NT1 Operating 

Hours 

PSNH shall maintain a log of the operating 

hours of the boiler. 

Continuously State Permit to 

Operate No. 

PO-B-1030 

13. NT1 Opacity PSNH shall install, certify, operate and 

maintain, a continuous opacity monitoring 

system with the automated data acquisition and 

handling system for measuring and recording 

the opacity of emissions (in percent opacity) 

for each 6-minute period for each unit. As 

necessary, PSNH shall also use US EPA 

Method 9 to estimate opacity. 

Continuously 40 CFR 

75.10(a)(4) 

and Env-A 

805.02 (old) 

and Env-A 

808.02 (a) 

(new) and 

807.02 (new) 

14. NT1 PM PSNH shall conduct stack testing using US 

EPA Method 1-5 or 1-4 and 17 or other 

method approved by DES to determine the PM 

emissions. PSNH shall calculate and record 

the PM emission rate in lb/MMBtu on a 24-

hour calendar day average and 

tons/consecutive 12-month period using stack 

test results and operating hours. PSNH may 

use other EPA-approved emission calculating 

methods to calculate PM emissions. 

Testing at least 

every 5 years 

and/or upon 

request by DES 

and/or EPA 

40 CFR 70.6 

(a)(3)(i)(B) 

15. NT1 CO PSNH shall install, certify, operate and

maintain a CO CEMS automated data 

acquisition and handling system for measuring 

and recording CO concentration (in ppm) 

averaged on an hourly and 24-hour calendar 

day basis, volumetric gas flow (in scfh), and 

CO mass emissions (in lb/hr averaged over one 

hour and each 24-hour calendar day, and 

tons/consecutive 12-month period and 

tons/calendar year) for each unit. PSNH shall 

conduct RATA testing for CO annually to 

verify the data. 

Continuously 40 CFR 70.6 

(a)(3)(i)(B)

16. NT1 Temperature 

of the flue gas 

at the outlet of 

the boiler 

PSNH shall measure and record the 

temperature at the outlet of the boiler to 

determine the inlet temperature of the ESP 

using a thermocouple or other temperaturemonitoring device. 

Daily 40 CFR 70.6 

(a)(3)(i)(B) 

17. NT1 Voltage of the 

TR Sets 

PSNH shall measure and record the secondary 

voltage of the TR Sets using a voltage meter or 

equivalent monitoring device. 

Daily 40 CFR 70.6 

(a)(3)(i)(B) 

18. NT1 Current (in 

mAmps and 

KW) 

PSNH shall measure and record the current (in 

mAmps and KW) using a current meter or 

equivalent monitoring device. 

Daily 40 CFR 70.6 

(a)(3)(i)(B) 

19. NT1 Spark rate per PSNH shall measure and record the spark rate Daily 40 CFR 70.6 
 PSNH Newington Page 31 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

minute per minute. (a)(3)(i)(B) 

20. NTI ESP fields out 

of service 

PSNH shall monitor and record the ESP fields 

out of service. 

Daily 40 CFR 70.6 

(a)(3)(i)(B) 

21. NT1 Hours that Fly 

Ash 

Reinjection 

System 

Blowers is in 

Operation 

PSNH shall maintain a log of the hours that the 

flyash reinjection system is operated. 

Daily when 

flyash reinjection 

is in operation 

40 CFR 70.6 

(a)(3)(i)(B) 

22. NT1 Toner Usage PSNH shall maintain records of the amount of 

toner combusted in the boiler in tons/day in 

order to demonstrate compliance with RSA 

125-I and Env-A 1400. 

Daily when 

combusting toner 

40 CFR 70.6 

(a)(3)(i)(B) 

23. NT1 SO2, NOx, 

CO, PM, 

VOCs 

Emissions 

(tons/month 

and tons/ 

consecutive 

12-month 

period) 

 Pursuant to the 40 CFR 52.21 (b)(21)(v) 

(dated July 1, 2002)14, for an electric utility 

steam generating unit (other than a new unit or 

the replacement of an existing unit), actual 

SO2, NOx, CO, PM, VOC emissions of the 

unit following the physical or operational 

change shall equal the representative actual 

annual emissions of the unit, provided PSNH 

maintains and submits to DES on an annual 

basis for a period of 5 years from the date the 

unit resumes regular operation, information 

demonstrating that the physical or operational 

change did not result in an emissions increase. 

A longer period, not to exceed 10 years, may 

be required by DES, if it determines such a 

period to be more representative of normal 

source post-change operations. Pursuant to 40 

CFR 52.21(b)(33) (dated July 1, 2002), 

representative actual annual emission means 

the average rate, in tons per year, at which the 

source is projected to emit a pollutant for the 

two-year period after the physical change or 

change in the method of operation of a unit (or 

a different consecutive two-year period within 

10 years after that change, where DES 

determines that such period is more 

representative of normal source operations), 

considering the effect any such change will 

have on increasing or decreasing the hourly 

Monthly 40 CFR 70.6 

(a)(3)(i)(B) 

and 40 CFR 

52.21 (b)(21) 

and (33), dated 

July 1, 2002 

 

14 See the letter dated March 13, 2002 from Kenneth A. Colburn, Director, Air Resources Division, DES to John M. McDonald, Vice 

President-Operations, PSNH concerning conditional new source review applicability determination concerning modifications at 

Newington Station. 
 PSNH Newington Page 32 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

emissions rate and on projected capacity 

utilization. In projecting future emissions, 

DES shall consider all relevant information, 

including but not limited to, historical 

operational data, the company’s own 

representations, filings with the State or 

Federal regulatory authorities, and compliance 

plans under Title IV of the CAA; and exclude, 

in calculating any increase in emissions that 

results from the particular physical change or 

change in the method of operation at an 

electric utility steam generating unit, that 

portion of the unit’s emissions following the 

change that could have been accommodated 

during the representative baseline period and is 

attributable to an increase in projected capacity 

utilization at the unit that is unrelated to the 

particular change, including any increased 

utilization due to the rate of electricity demand 

growth for the utility system as a whole. In 

order to calculate annual emissions as required 

pursuant to 40 CFR 52.21 (dated July 1, 

2002), PSNH shall monitor emissions of SO2, 

NOx, CO, PM, and VOCs for a period of 5 

years or more beginning in 2002. 

24. NT1 Fuel Flow 

MetersPeriodic 

Monitoring 

PSNH shall inspect, when NT1 is in operation, 

maintain and/or repair the fuel oil flow meters 

as necessary to ascertain accurate operation in 

accordance with manufacturer’s specifications. 

 PSNH and/or the manufacturer shall calibrate 

or validate accurate operation of the fuel oil 

flow meters during planned major turbinegenerator outages. 

During planned 

major turbinegenerator outages 

40 CFR 70.6 

(a)(3)(i)(B) 

25. NTAB1, 

NTAB2 

NOx 

Emissions (for 

NOx RACT) 

PSNH shall conduct stack testing using US 

EPA Method 7E to determine the NOx 

emissions. PSNH shall calculate and record the 

NOx emission rate in lb/MMBtu on a 24-hour 

calendar average, lb/hr on a 24-hour calendar 

average, and tons/consecutive 12-month period 

using fuel consumption measured with fuel 

meters and the stack test results and operating 

hours or other EPA-approved methods. 

Every 3 years 

and upon written 

request by DES 

and/or EPA 

Env-A 

1211.12 (e) 

and 1211.20 

and Env-A 

803.02 and 40 

CFR 70.6 

(a)(3)(i)(B) 

26. NTAB1, 

NTAB2, 

NTEG 

Opacity US EPA Method 9 As necessary as 

determined by 

PSNH, DES, 

and/or EPA 

40 CFR 70.6 

(a)(3)(i)(B)

27. NTAB1, 

NTAB2 

Sulfur Content 

of Propane 

Fuel delivery tickets, other documentation 

from the fuel supplier or testing in accordance 

with appropriate ASTM test methods that 

Upon request by 

DES and/or EPA 

Env-A 809.02 

(old) and EnvA 806.03 
 PSNH Newington Page 33 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

certify the weight-percent of sulfur for each 

delivery of the propane. 

(new) 

28. NTAB1, 

NTAB2 

Operating 

hours 

PSNH shall maintain a log of the operating 

hours of each device. 

Monthly State Permits 

to Operate 

Nos. PO-B1031 and POB-1032 and 40 

CFR 70.6 

(a)(3)(i)(B) 

29. NTAB1, 

NTAB2 

TSP PSNH shall conduct stack testing using US 

EPA Method 1-5 or 1-4 and 17 to determine 

the TSP emission rate in lb/MMBtu. PSNH 

shall calculate and record the TSP emission 

rate in lb/MMBtu averaged over 24-hour 

calendar day using fuel consumption data and 

EPA approved emission factors or stack test 

results. 

Stack testing 

upon request by 

DES and/or EPA 

40 CFR 70.6 

(a)(3)(i)(B) 

30. NTAB1, 

NTAB2 

Fuel 

Consumption 

PSNH shall measure and record the amount of 

fuel consumed using fuel flow meters and/or 

inventory purchase records. 

Monthly 40 CFR 70.6 

(a)(3)(i)(B) 

31. NTEG Operating 

hours 

PSNH shall maintain and operate an elapsed 

time meter to indicate the elapsed operating 

time in cumulative hours for the previous 12 

months. PSNH shall use the operating hours 

and assumed fuel feed rate to calculate the 

amount of fuel consumed. 

Continuously 

and annually for 

fuel consumption 

State Permit to 

Operate No. 

PO-B-1842 

and 40 CFR 

70.6 

(a)(3)(i)(B) 

32. NTAB1, 

NTAB2 

Fuel Flow 

MetersPeriodic 

Monitoring 

PSNH shall ensure that the fuel flow metering 

devices are calibrated according to 

manufacturer specifications or in a manner 

approved by the Division and at frequency 

consistent with manufacturer 

recommendations, but at a minimum every five 

calendar years. 

According to 

manufacturer 

recommendation, 

but at a 

minimum every 

five calendar 

years 

40 CFR 70.6 

(a)(3)(i)(B) 

33. NT1 CEM Hourly 

Operating 

Requirements 

& Valid Hour 

of CEM Data 

Pursuant to Env-A 808.01 and 808.03 and 40 

CFR 75.10(d), the Permittee shall ensure that 

the CEMS and components meet the following 

hourly operating requirements: 

A) The Permittee shall ensure that each CEM 

is capable of completing a minimum of 

one cycle of operation (sampling, 

analyzing, and data recording) for each 

Hourly 40 CFR 

75.10(d) and 

Env-A 

808.01(i) and 

808.03 

 

15 The requirements of 40 CFR 75 are less stringent than Env-A 808. 40 CFR 75 requires hourly averages to be computed using at 

least one data point in each fifteen-minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. 40 CFR 

75 allows an hourly average to be computed from at least two data points separated by a minimum of 15 minutes (where the unit 

operates for more than one quadrant of an hour) if data are unavailable as a result of the performance of calibration, quality assurance, 

or preventive maintenance activities pursuant to 40 CFR 75.21 and 40 CFR Appendix B or backups of data from the data acquisition 

and handling system, or recertification, pursuant to 40 CFR 75.20. 
 PSNH Newington Page 34 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

successive 15-minute interval pursuant to 

40 CFR 75.10(d) and pursuant to Env-A 

808.03(c)(2) for each successive 5-minute 

period for gaseous emissions, unless a 

longer time period is approved in 

accordance with Env-A 809 

B) The Permittee shall reduce all SO2

concentrations, volumetric flow, SO2 mass 

emissions, CO2 concentration, CO2 mass 

emissions (if applicable), NOx 

concentration, and NOx emission rate data 

collected by the monitors to hourly 

averages. 

C) The Permittee shall use all valid 

measurements or data points collected 

during an hour to calculate the hourly 

averages. All data points collected during 

an hour shall be, to the extent practicable, 

evenly spaced over the hour. 

D) Failure of an SO2 or CO2 pollutant 

concentration monitor, NOx concentration 

monitor, flow monitor, or NOx-diluent 

CEMS to acquire the minimum number of 

data points for calculation of an hourly 

average shall result in the failure to obtain 

a valid hour of data and the loss of such 

component data for the entire hour. 

E) For a NOx-diluent monitoring system, an 

hourly average NOx emission rate in 

lb/mmBtu is valid only if the minimum 

number of data points is acquired by both 

the NOx pollutant concentration monitor 

and the diluent monitor (CO2). 

F) If a valid hour of data is not obtained, the 

Permittee shall estimate and record 

emissions or flow data for the missing 

hour by means of the automated data 

acquisition and handling system, in 

accordance with the applicable procedure 

for missing data. 

G) Pursuant to Env-A 808.01(i), a valid hour 

of CEM emissions data means a minimum 

of 42 minutes of CEM readings taken in 

any calendar hour, during which the CEM 

is not in an out of control period and the 

facility is in operation.15

 

H) Pursuant to Env-A 808.03(a), PSNH shall 

average and record the CEM data for 

gaseous emissions for each calendar hour. 
 PSNH Newington Page 35 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

I) Pursuant to Env-A 808.03(c)(1), all CEM 

systems shall include a means to display 

instantaneous values of percent opacity 

and gaseous emission concentrations. 

34. NT1 Stack 

Volumetric 

Flow 

Measuring 

Device 

PSNH shall meet the following requirements 

for the stack volumetric flow measuring 

device: 

A) All differential pressure flow monitors 

shall have an automatic blow-back purge 

system installed and in wet conditions, 

shall have the capability for drainage of 

the sensing lines; and 

B) The stack flow monitoring system shall 

have the capability for manual calibration 

of the transducer while the system is online and for a zero check. 

Continuously Env-A 

808.03(d) 

35. NT1 Minimum 

Measurement 

Capability 

Requirements 

for CEMS 

The Permittee shall ensure that each CEMS is 

capable of accurately measuring, recording, 

and reporting data, and shall not incur an 

exceedance of the full scale range, except as 

provided in 40 CFR 75 Appendix A Sections 

2.1.1.5, 2.1.2.5, and 2.1.4.3. 

As specified by 

regulation 

40 CFR 

75.10(f) 

36. NT1 COMS Hourly 

Operating 

Requirements 

Pursuant to 40 CFR 75.10(d), the Permittee 

shall ensure that each COMS and components 

meet the following hourly operating 

requirements: 

A) The Permittee shall ensure that each 

continuous opacity monitoring system is 

capable of completing a minimum of one 

cycle of sampling and analyzing (and 

recording pursuant to Env-A 808.03(c)(2) 

unless a longer time period is approved in 

accordance with Env-A 809) for each 

successive 10-second period and one cycle 

of data recording for each successive 6-

minute period. 

B) The Permittee shall reduce all opacity data 

to 6-minute averages calculated in 

accordance with the provisions of 40 CFR 

51 Appendix M, except where the SIP or 

operating permit requires a different 

averaging period, in which case the State 

requirement shall satisfy this Acid Rain 

Program requirement as shown below. 

C) Pursuant to Env-A 808.03(b)(1), PSNH 

shall average the opacity data to result in 

consecutive, non-overlapping 6-minute 

averages; and 

D) Pursuant to Env-A 808.03(b)(2), for units 

Sampling for 

successive 10-

second period 

and recording for 

successive 6-

minute period 

40 CFR 

75.10(d) and 

Env-A 

808.03(b) and 

(c) 
 PSNH Newington Page 36 

 TV-OP-054 

Table 9 – Monitoring/Testing Requirements

Item 

No. 

Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

subject to the Env-A 2002.04(b) 

exemption, the total number of minutes in 

any 8-hour period where the opacity, as 

averaged in non-overlapping 6-minute 

periods, exceeds the applicable opacity 

standard. 

E) Pursuant to Env-A 808.03(c)(1), all CEM 

systems shall include a means to display 

instantaneous values of percent opacity 

and gaseous emission concentrations. 

37. NT1 Specific 

Provisions for 

Monitoring 

SO2 Emissions 

(SO2

emissions and 

flow monitors)

A) Pursuant to 40 CFR 75.11, the Permittee 

shall meet the specific provisions for SO2 

CEMS and flow monitoring systems: 

PSNH shall meet the general operating 

requirements in 40 CFR 75.10 for an SO2

continuous emission monitoring system 

and a flow monitoring system. 

B) During hours when the unit combusts only 

gaseous fuel, PSNH shall determine SO2

emissions in accordance with 40 CFR 

75.11 (e)(1), (e)(2) or (e)(3). 

C) Pursuant to 40 CFR 75.11 (e)(3), PSNH 

may determine SO2 mass emissions using 

a certified SO2 continuous monitoring 

system, in conjunction with a certified 

flow rate monitor system. However, when 

the unit burns any gaseous fuel that is very 

low sulfur fuel, as defined by 40 CFR 

72.2, the SO2 monitoring system shall be 

subject to the quality assurance provisions 

of 40 CFR 75.11 (e)(3). 

As specified by 

regulations 

40 CFR 75.11 

38. NT1 Specific 

Provisions for 

Monitoring 

NOx 

Emissions 

A) Pursuant to 40 CFR 75.12, 75.71, and 

75.72 and Env-A 3212, the Permittee shall 

meet the specific provisions for NOxdiluent CEMS, including the following: 

1) Meet general operating requirements 

in 40 CFR 75.10 for a NOx 

continuous emission monitoring 

system. The diluent gas monitor in 

the NOx CEMS may measure either 

O2 or CO2 concentration in the flue 

gases. 

2) Comply with NOx emission rate 

procedures contained in 40 CFR 

75.12(c). 

B) The Permittee shall meet the annual and 

ozone season monitoring requirements 

according to 40 CFR 75.74, as applicable. 

Continuously 40 CFR 75.12, 

75.71, and 

75.72 and 

Env-A 3212 

39. NT1 Specific Pursuant to 40 CFR 75.13, the Permittee shall Continuously 40 CFR 75.13 
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Device Parameter Method of Compliance Frequency of 

Method 

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Provisions for 

Monitoring 

CO2

Emissions 

meet the specific provisions for CO2 CEMS 

and flow monitoring systems. 

40. NT1 Specific 

Provisions for 

Monitoring 

Opacity 

Pursuant to 40 CFR 75.14, the continuous 

opacity monitoring and recording system shall 

meet all the design, installation, equipment, 

and performance specifications of 40 CFR 60, 

Appendix B, Performance Specification 1, and 

all the operational and quality assurance 

requirements of Env-A 808 (new). 

Continuously 40 CFR 75.14 

and Env-A 

808 (new) 

41. NT1 CEMS and 

COMS and 

Alternative 

Monitoring 

Certification 

Pursuant to 40 CFR 75.20 and 40 CFR 

75.70(d) and Env-A 3212.07 and Env-A 

3212.10, the Permittee shall recertify the 

CEMS and COMS and alternative monitoring 

system whenever the Permittee makes a 

replacement, modification, or change to the 

systems or to the facility that could 

significantly affect the ability of the systems to 

accurately measure and record the requisite 

data. The Permittee must submit an application 

for recertification of the monitoring system to 

EPA and DES. 

Whenever the 

Permittee makes 

a replacement, 

modification, or 

change to the 

systems or to the 

facility that could 

significantly 

affect the ability 

of the systems to 

accurately 

measure and 

record the 

requisite data 

40 CFR 75.20, 

40 CFR 

75.70(d), and 

40 CFR 75 

Appendix E 

Section 1.2 

and Env-A 

3212.02, 

3212.06, 

3212.07, 

3212.09, 

3212.10 and 

2910.04 

42. NT1 QA/QC 

Requirements 

A) Pursuant to 40 CFR 75.21 (a)(1) and 40 

CFR 75.70, the Permittee shall operate, 

maintain, and calibrate each CEMS 

according to the quality assurance and 

quality control procedures in 40 CFR 75 

Appendix B. 

B) Pursuant to 40 CFR 75.21 (a)(4), PSNH is 

not required to perform the daily and 

quarterly assessments of the SO2

monitoring system on any day or any 

quarter when only gaseous fuel is 

combusted, if the SO2 emissions are 

determined in accordance with 40 CFR 

75.11 (e)(1) or (e)(2). However, if any 

daily calibration test or linearity test is 

failed when the unit is combusting gaseous 

fuel only, the SO2 monitoring system is 

out-of-control. The length of the out-ofcontrol period shall be determined 

according to 40 CFR 75 Appendix B 

Section 2.1.4 or 2.2.3. 

C) Pursuant to 40 CFR 75.21 (a)(5), PSNH 

shall perform the relative accuracy test 

audits of the SO2 monitoring system only 

As specified by 

regulation 

40 CFR 75.21 

and 75.70 and 

75.74 
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Regulatory 

Cite 

when the higher-sulfur fuel is combusted. 

D) Pursuant to 40 CFR 75.21(b), the 

Permittee shall operate, calibrate, and 

maintain each COMS according to the 

procedures specified in the SIP, pursuant 

to 40 CFR 51 Appendix M. 

E) Pursuant to 40 CFR 75.21(c), the 

Permittee shall ensure that all calibration 

gases used to quality assure the operation 

of the instrumentation shall meet the 

definition in 40 CFR 72.2. 

F) Pursuant to 40 CFR 75.21(d) and (e), the 

Permittee shall comply with the provisions 

concerning consequences of audits and 

audit decertification. 

G) Within and prior to the ozone season, the 

Permittee shall meet the quality assurance 

requirements contained in 40 CFR 75.74, 

as applicable. 

43. NT1 Reference 

Test Methods 

for 

Certification 

and 

Recertification 

of CEMS or 

COMS 

The Permittee shall use the reference test 

methods listed in 40 CFR 75.22 and included 

in Appendix A to 40 CFR 60 to conduct 

monitoring system tests for certification or 

recertification of CEMS and excepted 

monitoring systems under 40 CFR 75 

Appendix E and quality assurance and quality 

control procedures. 

During 

certification or 

recertification 

tests 

40 CFR 75.22 

44. NT1 Out-ofControl 

Periods 

A) Pursuant to 40 CFR 75.21(e)(2), whenever 

a CEMS or COMS fails a quality 

assurance audit or any other audit, the 

system is out-of-control, and the Permittee 

shall follow the procedures for out-ofcontrol periods in 40 CFR 75.24. 

B) Pursuant to Env-A 3212.10 and 2910.06, 

whenever any monitoring system fails to 

meet the quality assurance requirements of 

40 CFR 75 Appendix B, PSNH shall 

substitute the data using the applicable 

procedures in 40 CFR 75, Subpart D, 

Appendix D or E. 

C) Pursuant to 75.24, if an out-of-control 

period occurs to a monitor or CEMS, the 

owner or operator shall take corrective 

action and repeat the tests applicable to the 

out of control parameter as described in 40 

CFR 75 Appendix B. 

1) For daily calibration error tests, an out 

of control period occurs when the 

calibration error of a pollutant 

As specified by 

regulation 

40 CFR 

75.21(e)(2) 

and 75.24 and 

Env-A 

3212.10 and 

2910.06 and 

808.01(g) 
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Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

concentration monitor exceeds 5.0% 

based upon the span value, the 

calibration error of a diluent gas 

monitor exceeds 1.0% O2 or CO2, or 

the calibration error of a flow monitor 

exceeds 6.0% based upon the span 

value, which is twice the applicable 

specification in 40 CFR 75 Appendix 

A. 

2) For quarterly linearity checks, an out 

of control period occurs when the 

error in linearity at any of the three gas 

concentrations (low, mid-range, and 

high) exceeds the applicable 

specification in 40 CFR 75 Appendix 

A. 

3) For relative accuracy test audits 

(RATAs), cylinder gas audit (CGAs), 

and relative accuracy audits (RAAs), 

an out of control period occurs when 

the sampling is completed and the 

CEMS fails the accuracy criteria until 

successful completion of the same 

audit after corrective action has 

occurred. 

D) Pursuant to Env-A 3212.10, whenever 

both an audit of a monitoring system and a 

review of the initial certification or 

recertification application reveal that any 

system or component should not have been 

certified or recertified because it did not 

meet a particular performance 

specification or other requirement pursuant 

to Env-A 800 or the applicable provisions 

of 40 CFR Part 75, both at the time of the 

initial certification or recertification 

application submission and at the time of 

the audit, the department shall issue a 

notice of disapproval of the certification 

status of such system or component. 

E) For the purposes of this section, an audit 

shall be either a field audit or an audit of 

any information submitted to the 

department or the administrator. 

F) The data measured and recorded by the 

system or component shall not be 

considered valid quality-assured data from 

the date of issuance of the notification of 

the disapproval of certification status until 
 PSNH Newington Page 40 

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Method 

Regulatory 

Cite 

the date and time that the owner or 

operator completes subsequently approved 

initial certification or recertification tests 

in accordance with Env-A 3212.07(t). 

G) The owner or operator shall follow the 

initial certification or recertification 

procedures for each disapproved system. 

45. NT1 Out of Control 

Periods for 

Opacity 

Out of control period for a CEMS measuring 

opacity is as follows: 

A) The time period beginning with the 

completion of the daily calibration drift 

check where the CD exceeds 2% opacity 

for 5 consecutive days, and ending with 

the CD check after corrective action has 

occurred that results in the performance 

specification drift limits being met; 

B) The time period beginning with the 

completion of a daily CD check preceding 

the daily CD check that results in the CD 

being greater than 5% opacity and ending 

with the CD check after corrective action 

has occurred that results in the 

performance specification drift limits 

being met; or 

C) The time period beginning with the 

completion of a quarterly opacity audit 

where the CEMS fails the calibration error 

test as specified in 40 CFR 60, Appendix 

B, Specification 1 and ending with 

successful completion of the same audit 

where the CEMS passes the calibration 

error test established after corrective action 

has occurred. 

As specified by 

regulation 

Env-A 

808.01(g)(2) 

46. NT1 Data 

Availability 

and Missing 

Data 

Substitution 

Procedures 

A) The Permittee shall follow the procedures 

in 40 CFR 75.30 through 75.37, 75.70(f), 

75.74, and 40 CFR 75 Appendix E when a 

valid, quality-assured hour of data is not 

measured or recorded. 

B) Pursuant to Env-A 808.02(c)(2), PSNH 

shall comply with the minimum 

percentage data availablity requirements 

pursuant to Env-A 808.10(a)-(d) to meet 

the requirements of Env-A 3200, NOx 

Budget Program. 

C) Pursuant to Env-A 808.10, if PSNH 

cannot meet the percentage data 

availability requirements, PSNH shall also 

follow the provisions of Env-A 808.10(e) 

– (g). 

As specified by 

regulation 

40 CFR 75.30 

through 75.37 

and 75.50(f) 

and 75.24(e) 

and 75.74 and 

40 CFR 75 

Appendix E 

Section 2.5 

and Env-A 

808.10 and 

808.02(c)(2) 
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Regulatory 

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D) Pursuant to 40 CFR 75.24(e), if COMS is 

out of control, PSNH shall follow the data 

availability requirements of Env-A 808.10. 

47. NT1 General CEM 

Requirements 

A) Pursuant to 40 CFR 75.5 (b), the Permittee 

must operate NT1 in compliance with the 

requirements of 40 CFR 75.2 through 

75.75 and 40 CFR 75 Appendices A 

through G. 

B) Pursuant to 40 CFR 75.5 (d), the Permittee 

shall account for all emissions of SO2, 

NOx, and CO2 in accordance with 40 CFR 

75.10 through 75.19. 

C) Pursuant to 40 CFR 75.5 (e), the Permittee 

shall not disrupt the continuous emission 

monitoring system or other approved 

emission monitoring method, and thereby 

not monitor or record SO2, NOx, and CO2, 

except for periods of recertification, or 

periods when calibration, quality 

assurance, or maintenance is performed 

pursuant to 40 CFR 75.21 and 40 CFR 75 

Appendix B. 

D) The CEMS shall meet the most stringent 

requirements of 40 CFR 75 and Env-A 

808 (new). 

Continuously 40 CFR 75.5 

and Env-A 

808 (new) 

48. NT1 CEMS 

Performance 

and Audit 

Requirements 

The Permittee shall ensure that each CEMS 

meets the following requirements: 

A) Each CEMS meets equipment, installation, 

and performance specifications in 40 CFR 

75 Appendix A; 

B) Each CEMS is maintained according to 

the quality assurance and quality control 

procedures in 40 CFR 75 Appendix B; and 

C) Each CEMS shall record SO2 and NOx 

emissions in the appropriate units of 

measurement. 

D) PSNH shall comply with the most 

stringent CEM audit requirements 

contained in 40 CFR 75 and Env-A 

808.07, General Audit Requirements, EnvA 808.08, Audit Requirements for 

Gaseous CEM Systems, and Env-A 

808.09, Audit Requirements for Opacity 

CEM Systems. 

As specified by 

regulation 

40 CFR 

75.10(b) and 

Env-A 808.07, 

808.08, and 

808.09 and 40 

CFR 75 

Appendices A 

and B 

49. NT1 NOx Mass 

Emissions – 

General 

Provisions 

Pursuant to Env-A 3200, NOx Budget 

Program, PSNH shall comply with the 

provisions of 40 CFR 75 Subparts A, C, D, E, 

F, and G and Appendices A through G 

applicable to NOx concentration, flow rate, 

As specified by 

regulation 

Env-3212.01 

and 40 CFR 

75.70(a) 
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Device Parameter Method of Compliance Frequency of 

Method 

Regulatory 

Cite 

NOx emission rate and heat input, as set forth 

and referenced in Subpart H. 

50. NT1 NOx Mass 

Emissions 

ProvisionsProhibitions 

PSNH is prohibited from the following: 

A) Using alternative monitoring system, 

reference method, or any other alternative 

for the required CEMS without approval 

through petition process in 40 CFR 

75.70(h). 

B) Discharging or allowing discharge of NOx 

emissions without accounting for all 

emissions in accordance with the 

provisions of Subpart H, except as 

provided in 40 CFR 75.74. 

C) Disrupting the CEMS or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording NOx mass emissions, except for 

periods of re-certification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the provisions of 40 CFR 75 Subpart 

H applicable to the monitoring systems 

under 40 CFR 75.71, except as provided 

in 40 CFR 75.74. 

D) Retiring or permanently discontinuing the 

use of the CEMS, or any other approved 

emission monitoring system except under 

one of the following circumstances: 

1) During a period that the unit is 

covered by a retired unit exemption 

that is in effect under the State or 

federal NOx mass emission reduction 

program that adopts the requirements 

of Subpart H; 

2) The owner or operator is monitoring 

NOx emissions from the affected unit 

with another certified monitoring 

system approved, in accordance with 

the provisions of 40 CFR 75.70(d); or 

3) The designated representative submits 

notification of the date of certification 

testing of a replacement monitoring 

system in accordance with 40 CFR 

75.61. 

Continuously 40 CFR 

75.70(c) 

51. NT1 NOx Mass 

Emissions – 

Petitions for 

Alternatives 

PSNH may submit a petition to DES and EPA 

requesting an alternative to any requirement of 

40 CFR 75 Subpart H. Such a petition shall 

meet the requirements of 40 CFR 75.66 and 

any additional requirements established by 

Not applicable 40 CFR 

75.70(h) and 

40 CFR 75 

Subpart E and 

40 CFR 75 
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Device Parameter Method of Compliance Frequency of 

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Regulatory 

Cite 

Env-A 3200 or other applicable state or 

Federal NOx mass emission reduction 

programs that adopt the requirements of 40 

CFR 75 Subpart H. 

Appendix E 

and Env-A 

3212.09 

52. NT1 NOx Mass 

Emissions – 

NOx Emission 

Rate and Heat 

Input –Oil/Gas 

Non-Peaking 

Units 

For an affected unit that qualifies as a nonpeaking gas-fired or non-peaking oil-fired unit, 

PSNH shall either: 

A) Meet the requirements of 40 CFR 75.71(a) 

and (b); or 

B) Meet the general operating requirements in 

40 CFR 75.10 for NOx diluent continuous 

emission monitoring system, except as 

provided in accordance with 40 CFR 75 

Subpart E, and use the procedures 

specified in 40 CFR 75 Appendix D for 

determining hourly heat input. The heat 

input apportionment provisions in Section 

2.1.2 of 40 CFR 75 Appendix D shall not 

be used to meet the NOx mass reporting 

provisions of 40 CFR 75 Subpart H. 

As specified by 

regulation 

40 CFR 

75.71(c) 

53. NT1 NOx Mass 

Emissions – 

Annual 

Monitoring 

PSNH shall meet the requirements of 40 CFR 

75 Subpart H during the entire calendar year. 

During the 

calendar year 

40 CFR 

75.74(a) and 

(b) 

54. NT1 Valid 

Averaging 

Periods for 

Gaseous and 

Opacity 

CEMS 

The number of hours of valid CEM and COM 

data required for determining a valid averaging 

period for the different emission standard 

periods shall be: 

A) For a 3-hour emission standard period, 2 

hours of valid data; 

B) For a 4-hour emission standard period, 3 

hours of valid data; 

C) For an 8-hour emission standard period, 6 

hours of valid data; 

D) For a 12-hour emission standard period, 9 

hours of valid data, and 

E) For a 24-hour emission standard period, 18 

hours of valid data. 

As specified by 

regulation 

Env-A 808.14 

and 805.09 

(old) 

55. Facility 

wide 

Inventories of 

Regulated 

Substances 

PSNH shall monitor the quantity of regulated 

substances to ensure that facility is in 

compliance with the requirements of 40 CFR 

68. 

Continuously 40 CFR 68 

and 1990 

CAA Section 

112(r)(1) 

I. Recordkeeping Requirements 

The Permittee is subject to the Recordkeeping requirements as contained in Table 10 below: 
 PSNH Newington Page 44 

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Table 10 – Applicable Recordkeeping Requirements16

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

1. Liquid Fuel Utilization Records: The Permittee 

shall maintain the following monthly records, 

or records for an alternative period as approved 

by DES in accordance with Env-A 912, of the 

liquid fuel characteristics and utilization: 

A) Fuel consumption (monthly and 12-month 

rolling average); 

B) Fuel type; 

C) Viscosity (based on generally accepted 

values); 

D) Sulfur content as percent sulfur by weight 

of fuel; 

E) BTU content per gallon of fuel; and 

F) Hours of operation of each fuel combustion 

device while operating with each type of 

liquid fuel, so the distribution of fuel 

among each combustion device can be 

estimated. 

Monthly or an 

alternative period as 

approved by DES 

in accordance with 

Env-A 912 and for 

fuel consumption, 

monthly and 12-

month rolling 

average 

NT1, NTAB1, 

NTAB2, NTEG 

Env-A 901.03(a)(1) 

and (c) (old) and 

Env-A 903.03(a)(3) 

and (b) (new) 

2. Gaseous Fuel Utilization Records: The 

Permittee shall maintain the following monthly 

records, or records for an alternative period as 

approved by DES in accordance with Env-A 

912, of the fuel characteristics and utilization: 

A) Fuel consumption (monthly and 12-month 

rolling average); 

B) Fuel type; 

C) Sulfur content as percent sulfur by weight 

of fuel or in grains per 100 cubic feet of 

fuel (as tested upon request by DES and/or 

EPA); 

D) Hours of operation of each fuel combustion 

device while operating with each type of 

gaseous fuel, so the distribution of fuel 

among each combustion device can be 

estimated. 

 Monthly or an 

alternative period as 

approved by DES 

in accordance with 

Env-A 912 and for 

fuel consumption, 

monthly and 12-

month rolling 

average 

NT1, NTAB1, 

NTAB2 

 Env-A 

903.03(a)(4) (new) 

3. Monitoring Plan and QA/QC Plan: 

A) The Permittee shall prepare and maintain a 

monitoring plan for the CEMS and COMS, 

which contains sufficient information to 

demonstrate that all unit SO2 emissions, 

NOx emissions, CO2 emissions and opacity 

are monitored and reported. 

Whenever a change 

occurs that could 

affect monitoring 

method or annually, 

whichever is more 

frequent 

NT1 40 CFR 75.53 (a), 

(b), (e), and (f) and 

Env-A 808.06 and 

3212.13 and 

2910.09 

 

16 On April 23, 1999 DES promulgated new Env-A 900 rules to streamline the recordkeeping and reporting requirement sections of the 

New Hampshire Code of Administrative Rules. Until such time that the new Env-A 900 rules are approved and adopted into the State 

Implementation Plan (SIP) by EPA, all Title V permits will be incorporating the old Env-A 900 rules (which became effective on 

November 11, 1992), unless the new Env-A 900 rules are more stringent. These recordkeeping and reporting requirements shall fall 

under the Permit Shield provisions as contained in Section XIII of this permit. 
 PSNH Newington Page 45 

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Table 10 – Applicable Recordkeeping Requirements16

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

B) The Permitte shall prepare and maintain 

monitoring plans for other approved 

monitoring methods, which contain 

sufficient information to demonstrate that 

all unit NOx emissions are monitored and 

reported. 

C) The Permittee shall update the monitoring 

plan whenever the Permittee makes a 

replacement, modification or change that 

could affect the CEMS or COMS or other 

approved monitoring method. 

D) The Permittee shall review the QA/QC plan 

and all data generated by its 

implementation at least once each year. 

E) The Permittee shall revise or update the 

QA/QC plan, as necessary, based on the 

results of the annual review by conducting 

the following: 

1) Documenting any changes made to the 

CEM or the monitoring method or 

changes to any information provided in 

the monitoring plan; 

2) Including a schedule of, and 

describing, all maintenance activities 

that are required by the CEM 

manufacturer or that might have an 

effect on the operation of the system; 

3) Describing how the audits and testing 

required by this part will be performed; 

and 

4) Including examples of the reports that 

will be used to document the audits and 

tests required by this part; 

5) Make the revised QA/QC plan 

available for on-site review by the 

division at any time; and 

6) Within 30 days of completion of the 

annual QA/QC plan review, certify in 

writing that the owner or operator 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. 

F) The QA/QC plan shall be considered an 

update to the CEM monitoring plan 

required by Env-A 808.04. 

G) Pursuant to Env-A 3212.13(a) and Env-A 

2910.09, the unit subject to acid rain 

emission limitations (NT1) shall comply 
 PSNH Newington Page 46 

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Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

with the requirements of 40 CFR 75.62, 

except the monitoring plan shall also 

include all of the information required by 

40 CFR 75, Subpart H. 

4. CEM, COMS and Other Approved Monitoring 

Methods Recordkeeping Requirements: 

A) The Permittee shall record and maintain the 

information required pursuant to 40 CFR 

75.57, 75.58, 75.59, and 75.73(b), which 

includes the certification, quality assurance, 

and quality control records. 

B) The Permittee shall record and maintain 

CEMS and COMS records according to the 

most stringent requirements of Env-A 808 

and 40 CFR 75. 

As specified by 

regulation 

NT1 40 CFR 75.57, 

75.58,75.59, and 

75.73 and Env-A 

3212 and Env-A 

903.04 (a) (new) 

and Env-A 800 and 

40 CFR 75 

5. General NOx Recordkeeping Requirements:

The Permittee shall record and maintain the 

following information for fuel burning devices: 

A) Facility information, including the 

following: 

1) Source name; 

2) Source identification; 

3) Physical address; and 

4) Mailing address. 

B) Identification of fuel burning devices; 

C) Operating schedule for each fuel burning 

device identified in Condition B) above: 

1) Days per calendar week during the 

normal operating schedule; 

2) Hours per day during the normal 

operating schedule and for a typical 

ozone season day; and 

3) Hours per year during the normal 

operating schedule. 

D) Type and amount of fuel burned for each 

fuel-burning device during normal 

operating conditions and for a typical ozone 

season day, if different from normal 

operating conditions, on an hourly basis in 

mmBtu/hr. 

E) Theoretical potential NOx emissions for the 

calculation year for each fuel burning 

device: 

1) Annual emissions, in tons per year; and 

2) Typical ozone season day emissions, in 

pounds per day. 

F) Actual NOx emissions for each fuel 

burning device: 

1) Annual emissions, in tons per year; and 

Annually and as 

applicable 

NT1, NTAB1, 

NTAB2, NTEG 

Env-A 901.08 (c) 

(1)–(5) (old) and 

Env-A 905.02 

(new) 
 PSNH Newington Page 47 

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Table 10 – Applicable Recordkeeping Requirements16

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

2) Typical ozone season day emissions, in 

pounds per day. 

G) Emission factors and the origin of the 

emission factors used to calculate the NOx 

emissions. 

6. Sulfur Analysis Records for Fuel Oil: PSNH 

shall maintain delivery tickets from each fuel 

oil supplier for each shipment of fuel oil 

received. The delivery tickets shall be in a 

form suitable for inspection and available to the 

DES and/or EPA upon request. Each delivery 

ticket shall indicate the following: 

A) The name of the fuel supplier; 

B) The address of the fuel supplier; 

C) The telephone number of the fuel supplier; 

D) The type of fuel delivered; 

E) The quantity of fuel oil delivered; 

F) The date of delivery; and 

G) The maximum percent sulfur by weight of 

the fuel oil delivered. 

If the delivery tickets do not contain sulfur 

content of fuel delivered, the Permittee shall 

provide other documentation from the fuel 

supplier with the above information or perform 

testing in accordance with appropriate ASTM 

test methods to determine compliance with the 

sulfur content limitation provisions in Env-A 

1604 for liquid fuels. 

For each delivery of 

fuel oil 

NT1, NTAB1, 

NTAB2, NTEG 

Env-A 806.05 

(new) and 40 CFR 

70.6(a)(3) 

7. Delivery Ticket for Propane: PSNH shall 

maintain delivery tickets from each propane 

supplier for each shipment of propane received. 

 The delivery tickets shall be in a form suitable 

for inspection and available to the DES and/or 

EPA upon request. Each delivery ticket shall 

indicate the following: 

A) The name of the fuel supplier; 

B) The address of the fuel supplier; 

C) The telephone number of the fuel supplier; 

D) The type of fuel delivered; 

E) The quantity of propane delivered; 

F) The date of delivery. 

For each delivery of 

propane 

NTAB1, 

NTAB2 

Env-A 806.05 

(new) and 40 CFR 

70.6(a)(3) 

8. Natural Gas Utilization Records: PSNH shall 

maintain billing tickets for each natural gas 

supplier. The billing tickets shall be in a form 

suitable for inspection and available to the DES 

and/or EPA upon request. Each billing ticket 

shall indicate the following: 

A) The name of the fuel supplier; 

Monthly NT1 State Permit to 

Operate No. PO-B1030 
 PSNH Newington Page 48 

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Table 10 – Applicable Recordkeeping Requirements16

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

B) The address of the fuel supplier; 

C) The telephone number of the fuel supplier; 

and 

D) The quantity of natural gas used. 

9. Emergency Generator Operating Records:

PSNH shall record and maintain monthly and 

annual records of the operating hours of the 

emergency generator. 

Monthly NTEG State Permit to 

Operate No. PO-B1842 and 40 CFR 

70.6(a)(3) 

10. Auxiliary Boiler Operating Records: PSNH 

shall record and maintain monthly and 

consecutive 12-month records of the operating 

hours of each auxiliary boiler 

Monthly NTAB1, 

NTAB2 

State Permit to 

Operate No. PO-B1031 and PO-B1032 

11. Multipollutant Budget and Trading Program 

Recordingkeeping Requirements: PSNH shall 

comply with the recordkeeping requirements of 

the multipollutant budget and trading program. 

As required by 

RSA 125-O and 

Env-A 2900 

NT1 Env-A 2900 

12. Certificate of Representation: The Permittee 

shall complete and retain a certificate of 

representation for a designated representative or 

an alternate designated representative including 

the elements pursuant to 40 CFR 72.24, 

Certificate of representation. 

Maintain at the 

facility at all times 

NT1 40 CFR 72.24 

13. Record Retention: The Permittee shall retain 

the records required by this permit on file for a 

minimum of 5 years except the certificate of 

representation for the designated 

representatives shall be kept beyond the 5-year 

period.17

 

Retain for a 

minimum of 5 years 

or as specified 

Facility wide Env-A 902.01 (a) 

(new), Env-A 3213, 

40 CFR 70.6 

(a)(3)(ii)(B), and 40 

CFR 72.9 (f) 

14. Regulated Toxic Air Pollutant Records: The 

Permittee shall maintain records in accordance 

with the applicable method used to demonstrate 

compliance pursuant to Env-A 1405. 

Maintain at facility 

at all times 

All devices 

subject to RSA 

125-I and Env-A 

1400 

Env-A 902.01 (c) 

(new) State 

Enforceable Only 

15. Representative Actual Annual Emissions Test 

Recordkeeping Requirements: PSNH shall 

maintain records of SO2, NOx, CO, PM, and 

VOCs emissions in tons/month and tons per 

consecutive 12-month period for NT1. 

Monthly NT1 40 CFR 

52.21(b)(21) and 

(33), dated July 1, 

2002 and 40 CFR 

70.6(a)(3)(ii) and 

Env-A 906 

16. Monitoring Records: The Permittee shall 

maintain records of monitoring results as 

specified in Table 9 of this Permit including the 

following: 

A) Visible emission/opacity test results for 

NT1, NTAB1, NTAB2, and NTEG; 

B) NOx, SO2, CO2, continuous emissions 

Maintain as 

required in Table 9 

As specified for 

each monitoring 

record 

40 CFR 

70.6(a)(3)(ii) 

 

17 Note that record retention for five years is more stringent than the three year record retention required in some sections of 40 CFR 

75. 
 PSNH Newington Page 49 

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Table 10 – Applicable Recordkeeping Requirements16

Item 

No. 

Recordkeeping Requirement Frequency of 

Recordkeeping 

Applicable 

Emission Unit 

Regulatory Cite 

monitoring data for NT1; 

C) Stack volumetric flow rate for NT1; 

D) Heat input rate for NT1; 

E) PM emissions (in lb/MMBtu over a 24-

hour calendar day, tons per 12-month 

period) for NT1, NTAB1, and NTAB2; 

F) Toner usage in tons/day for NT1; 

G) Voltage of the transformer rectifier sets (TR 

Sets) for NT1-PC1; 

H) Temperature of flue gas at the outlet of the 

boiler (in degrees F) for NT-PC1; 

I) Current to ESP for NT1-PC1; 

J) Spark Rate in ESP for NT1-PC1; 

K) Fields out of service in ESP for NT1-PC1; 

L) Hours of operation of the flyash reinjection 

system for NT1; 

M) NOx, SO2, CO, and VOC emissions for the 

auxiliary boilers for NTAB1 and NTAB2; 

N) Net electrical output (MWh) for NT1; 

O) Flow metering calibrations for NT1, 

NTAB1, and NTAB2; and 

P) Quantities of regulated substances above 

the thresholds established by EPA under 40 

CFR 68.130 facilitywide. 

17. Operating Scenario Records: PSNH shall 

maintain a record of the scenarios under which 

it is operating. PSNH shall specify whether 

operation is under normal conditions or an 

alternative operating scenario listed in Section 

VII. PSNH shall specify which alternative 

operating scenario is in use. 

Whenever 

operation method 

changes from 

normal operation to 

a specific 

alternative 

operating scenario 

Facility wide 40 CFR 70.6 (a)(9) 

J. Reporting Requirements 

The Permittee is subject to the federally enforceable reporting requirements identified in Table 

11 below: 

Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

1. NOx Reporting Requirements: The Permittee 

shall submit reports of the NOx records kept 

pursuant to the Section VIII. I. Table 9, Applicable 

Recordkeeping Requirements. 

Annually (no later 

than April 15th of 

the following year) 

NT1, NTAB1, 

NTAB2, NTEG 

Env-A 901.09 

(old) and Env-A 

909.03 (new) 

2. State Acid Deposition Control Program Reporting 

Requirements: The Permittee shall submit an 

annual report of the fuel utilization information 

Annually (no later 

than April 15th of 

the following year) 

NT1 Env-A 907.02 

(new) 
 PSNH Newington Page 50 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

pursuant to Env-A 903.03 and Section VIII. I. 

Table 10, Applicable Recordkeeping 

Requirements. 

3. CEMS Recertification Notifications and Reports: 

A) The Permittee shall notify EPA and DES by 

telephone or in writing and not later than 21 

days prior to the first scheduled day of full 

recertification testing and at least 7 calendar 

days prior to the first scheduled day of partial 

recertification testing (when all of the tests are 

not required). In emergency situations when 

equipment fails with lost data, the Permittee 

may provide notice within 2 business days 

following the date when testing is scheduled. 

If the testing is rescheduled, the Permittee may 

notify DES and EPA by telephone or other 

means within 2 business days prior to the 

scheduled test date or the revised test date, 

whichever is earlier. 

B) Within 45 calendar days after completing all 

recertification tests, the Permittee shall submit 

to EPA and DES the electronic and hardcopy 

information contained in 40 CFR 75.63. 

C) Pursuant to Env-A 3212.14 and Env-A 

2910.10, PSNH shall submit an application to 

DES within 45 days after completing all initial 

certification or recertification tests including 

the information required under 40 CFR 75, 

Subpart H. 

D) Pursuant to Env-A 2910.07, PSNH shall also 

submit written notification required pursuant 

to 40 CFR 75.61 to the ATS administrator. 

7 days prior to 

partial 

recertification, 21 

days prior to full 

recertication, and 

45 days after all 

recertification tests 

NT1 40 CFR 75.61 

(a)(1), 75.70, 

75.63, and 

75.73(d) and 

Env-A 3212 

and 2910 

4. Relative Accuracy Test Audit (RATA) 

Notification and Reports: 

A) The Permittee shall submit written notice to 

EPA and DES no later than 21 calendar days 

prior to the first scheduled day of testing.18 If 

the testing is rescheduled, the Permittee may 

notify DES and EPA by telephone or other 

means no later than 24-hours in advance of the 

new testing date. DES shall require 

rescheduling of the RATA if staff necessary to 

observe the RATA are not available. 

B) If requested, the Permittee shall submit the 

quality assurance RATA reports to EPA and 

DES by the later of 45 days after completing a 

21 calendar days 

prior to RATA 

NT1 40 CFR 75.61 

(a)(5) and 

75.73(d) and 

Env-A 3212.11 

and 2910 and 

808.05 and 

808.07(c) and (d) 

 

18 Note that pursuant to Env-A 808.07, PSNH shall notify DES at least 30 days prior to the performance of the RATA. This 

requirement is less stringent than the requirement of 40 CFR 75. 
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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

quality assurance RATA or 15 days of 

receiving the request. 

C) Pursuant to Env-A 808.07(b), PSNH shall 

submit to DES a written report summarizing 

the testing within 30 days of the completion of 

the test. 

D) Pursuant to Env-A 2910.07, PSNH shall also 

submit written notification required pursuant 

to 40 CFR 75.61 to the ATS administrator. 

5. Performance Specification Testing Reports: 

A) DES shall be notified of the date or dates of 

the performance specification testing at least 

30 days prior to the scheduled dates. 

B) PSNH shall submit to DES a written report 

summarizing the testing within 30 days of the 

completion of the test. 

30-day notice to 

DES prior to test; 

test report to DES 

30 days after the 

test 

NT1 Env-A 808.05 

6. General Audit Notification Requirements: PSNH 

shall notify DES at least 2 weeks prior to any 

planned audit or test procedure except for RATAs, 

where PSNH shall provide at least 30 days notice 

prior to the performance of the RATA. 

2 weeks prior to 

any planned audit 

or test procedure 

and at least 30 days 

prior to the RATA. 

NT1 Env-A 808.07(c) 

and (e) 

7. Monitoring and QA/QC Plan Submittals: The 

Permittee shall submit to EPA and DES a 

complete, electronic, up-to-date monitoring plan at

the time of recertification application submission 

and in each electronic quarterly report, and 

whenever an update of the electronic monitoring 

plan information is required. 

In the 

recertification 

application, in each 

electronic quarterly 

report, and 

whenever an update 

of the electronic 

monitoring plan 

information is 

required 

NT1 40 CFR 75.62 

and 75.73(d) and 

(e) and Env-A 

808.04, 808.06, 

3212 and 2910 

8. Quarterly Reports: 

A) The Permittee shall submit to DES and EPA in 

electronic format or other format as approved 

by DES and/or EPA 30 calendar days after the 

end of the calendar quarter the information 

contained in 40 CFR 75.64(a), 40 CFR 

75.73(f), 40 CFR 75.74, Env-A 2912, Env-A 

3212, Env-A 3214, Env-A 808.11(new), and 

Env-A 808.13 (new) and the following 

information: 

1) Written report of opacity, SO2, NOx, and 

CO2 emissions as calculated by the 

CEMS. 

2) The 24-hour averages of the following 

shall be reported, whether or not an excess 

emission has occurred: 

a. SO2 lb/MMBtu, SO2 ppm, and SO2

lb/hr; 

30 calendar days 

after the end of the 

calendar quarter 

NT1 40 CFR 75.64, 40 

CFR 75.73(f), 40 

CFR 75.57(f), 40 

CFR 75.74, EnvA 2910, Env-A 

2911, Env-A 

3212, Env-A 

3214, Env-A 

808.11(new), 

Env-A 808.13 

(new), and State 

Permit to Operate 

No. PO-B-1030 
 PSNH Newington Page 52 

 TV-OP-054 

Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

b. NOx lb/MMBtu, NOx ppm, and NOx 

lb/hr; 

c. Percent CO2 and CO2 lb/hr as 

measured by continuous 

monitor/recorder; 

d. Stack volumetric flowrate (in kscfm); 

e. Load (in MW); 

f. Steam flow (in klbs/hr); 

g. Heat input (MMBtu/hr); and 

h. Opacity (in percent). 

3) Excess emission data recorded by the 

CEM system, including the following: 

a. The date and time of the beginning 

and ending of each of excess 

emissions; 

b. The magnitude of each excess 

emission; 

c. The specific cause of the excess 

emission; and 

d. The corrective action taken. 

4) If no excess emissions have occurred, a 

statement to that effect; 

5) For gaseous emission monitoring systems, 

the daily averages of the measurements 

made and emissions rates calculated. 

6) A statement as to whether the CEM 

system was inoperative, repaired, or 

adjusted during the reporting period; 

7) If the CEM system was inoperative, 

repaired, or adjusted during the reporting 

period, the following information: 

a. The date and time of the beginning 

and ending of each period when the 

CEM was inoperative; 

b. The reason why the CEM was not 

operating; 

c. The corrective action taken; and 

d. The percent data availability 

calculated in accordance with Env-A 

808.10 for each flow, diluent, or 

pollutant analyzer in the CEM system; 

8) The date and time beginning and ending 

each period when the source of emissions 

which the CEM system is monitoring was 

not operating; 

9) When calibration gas is used, the 

following information: 

a. The calibration gas concentration; 

b. If a gas bottle was changed during the 
 PSNH Newington Page 53 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

quarter: 

i) The date of the calibration gas 

bottle change; 

ii) The gas bottle concentration 

before the change; and 

iii) The gas bottle concentration after 

the change; and 

c. The expiration date for all calibration 

gas bottles used. 

10) Excess emissions of SO2 shall be defined 

as an annual SO2 emission, which exceeds 

the state acid rain emission limitation, as 

calculated from CEM data. 

B) The designated representative shall affirm that 

the component/system identification codes and 

formulas in the quarterly electronic reports 

represent current operating conditions. 

C) The designated representative shall submit a 

certification in support of each quarterly 

emissions monitoring report based on 

reasonable inquiry of those persons with 

primary responsibility for ensuring that all of 

the unit's emissions are correctly and fully 

monitored. 

D) The certification shall indicate whether the 

monitoring data submitted were recorded in 

accordance with the applicable requirements 

of this part including the quality control and 

quality assurance procedures and 

specifications of 40 CFR 75, and any such 

requirements, procedures and specifications of 

an applicable excepted or approved alternative 

monitoring method. 

E) For a unit with add-on emission controls, the 

designated representative shall also include a 

certification, for all hours where data are 

substituted following the provisions of 40 

CFR 75.34(a)(1), that the add-on emission 

controls were operating within the range of 

parameters listed in the monitoring plan and 

that the substitute values recorded during the 

quarter do not systematically underestimate 

SO2 or NOx emissions, pursuant to 40 CFR 

75.34. 

F) For a unit that is reporting on a control period 

basis, the designated representative shall also 

include a certification that the NOx emission 

rate and NOx concentration values substituted 

for missing data under 40 CFR 75 Subpart D 
 PSNH Newington Page 54 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

are calculated using only values from a control 

period and do not systematically underestimate 

NOx emissions. 

G) Pursuant to Env-A 3212.15(e) and Env-A 

2910.11(a)(3), the quarterly reports shall be 

submitted in the manner specified in 40 CFR 

75, Subpart H and 40 CFR 75.64. 

H) Pursuant to Env-A 3212.15(f) and Env-A 

2910.11(a)(4), for NT1 the quarterly reports 

shall include all of the data and information 

required in 40 CFR Subpart H and 40 CFR 

Subpart G. 

I) Pursuant to Env-A 3214.01 and Env-A 

2911.01, PSNH shall also submit emissions 

and operations information in electronic 

format as part of the quarterly reports. 

J) Pursuant to Env-A 3214.02, PSNH shall also 

submit to the NETS administrator in the 

quarterly reports, NOx emissions in lb/hr for 

every hour during the control period and 

cumulative quarterly and seasonal NOx 

emission data in pounds. 

K) Pursuant to Env-A 2911.02, PSNH shall also 

submit to the ETS administrator in the 

quarterly reports, SO2, NOx and CO2

emissions in lb/hr for every hour during the 

year and cumulative quarterly and annual SO2, 

NOx and CO2 emissions data in pounds. 

9. Offset Plans for Excess SO2 Emissions: The 

Permittee shall submit an offset plan no later than

60 days after the end of any calendar year during 

which a unit has excess SO2 emissions. The offset 

plan shall contain the information pursuant to 40 

CFR 77.3. 

60 days after the 

end of any calendar 

year 

NT1 40 CFR 77.3 

10. Quarterly Audit Reports: Pursuant to Env-A 

808.07 (new), the Permittee shall submit to DES, a 

written summary report of the results of all 

required audits that were performed in that quarter, 

in accordance with the following: 

A) For gaseous CEM audits, the report format 

shall conform to that presented in 40 CFR 60, 

Appendix F, Procedure 1, Section 7; and 

B) For opacity CEM audits, the report format 

shall conform to that presented in EPA-600/8-

87-025, April 1992, “Technical Assistance 

Document: Performance Audit Procedures for 

Opacity Monitors.” 

Quarterly, no later 

than 30 calendar 

days after the end 

of the quarter for 

which reporting is 

required 

NT1 Env-A 808.07 

(new) 

11. Quarterly Fuel Data Reports: The Permittee shall 

submit the fuel data listed in Table 10 above 

Quarterly, no later 

than 30 calendar 

NT1, NTAB1, 

NTAB2 

Env-A 910 and 

State Permits to 
 PSNH Newington Page 55 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

summarized on a monthly basis and for the 

previous 3 quarters in addition to the current 

reporting quarter. The Permittee shall submit 

monthly fuel usage information, including fuel 

type and the sulfur content by device. 

days after the end 

of the quarter for 

which reporting is 

required 

Operate Nos. POB-1030, PO-B1031, and PO-B1032 

12. Annual Fuel Data Reports: The Permittee shall 

submit quarterly fuel usage information for the 

emergency generator on a calendar year basis. 

Annually (no later 

than April 15th of 

the following year) 

NTEG Env-A 910 and 

State Permits to 

Operate Nos. POB-1842 

13. Performance Test Reports: The Permittee 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 Permittee 

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 

Facility wide Env-A 802.11 

(new) 

14. Net Electrical Output Reporting – The Permittee 

shall report monthly data19 of the net electrical 

output of each affected source for the calendar 

year and the ozone season to DES. 

Annually (no later 

than April 15th of 

the following year) 

NT1 Env-A 

2906.05(g) and 

3207.04(k) 

15. Regulated Toxic Air Pollutant Reports: The 

Permittee shall report actual emissions speciated 

by individual regulated toxic air pollutants, 

including a breakdown of VOC emission 

compounds. 

Annually (no later 

than April 15th of 

the following year) 

Facility wide Env-A 907.01 

(new) 

State Enforceable 

Only 

16. Representative Actual Annual Emissions Test 

Emissions Reporting Requirements: PSNH shall 

submit to DES annually SO2, NOx, CO, PM, and 

VOCs emissions in tons/month and consecutive 

12-month period for NT1. 

Annually (no later 

than April 15th of 

the following year) 

NT1 40 CFR 

52.21(b)(21) and 

(33), dated July 1, 

2002 and Env-A 

910 (new) 

17. Semi-Annual Permit Deviation/Monitoring 

Reports: The Permittee shall submit a permit 

deviation/monitoring report of the data specified in 

Semiannually (by 

July 31st and 

January 31st of each 

Facility wide 40 CFR 

70.6(a)(3)(iii)(A)

and Env-A 

 

19 Copies of the Forms EIA-906 and EIA-920 are sufficient. 
 PSNH Newington Page 56 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

Table 9 of this Permit every 6 months. All 

required reports must be certified by a responsible

official consistent with 40 CFR 70.5(d). The 

report shall contain a summary of the following 

information, unless this information was provided 

(or will be provided) to DES pursuant to another 

requirement: 

A) Visible emission/opacity test results for NT1, 

NTAB1, NTAB2, and NTEG; 

B) Summary showing monthly average sulfur 

content of the liquid and gaseous fuels from 

testing and/or delivery ticket and/or other 

documentation certifications for liquid and 

gaseous fuel sulfur content for NT1, NTAB1, 

and NTAB2; 

C) NOx, SO2, CO2, continuous emissions 

monitoring data for NT1; 

D) PM emissions (in lb/MMBtu over a 24-hour 

calendar day, tons per 12-month period) for 

NT1, NTAB1, and NTAB2; 

E) Toner usage in tons/day and an indication of 

the combustion of any new toners for NT1; 

F) Hours of operation without the flyash 

reinjection system for NT1; 

G) NOx, SO2, CO, and VOC emissions for the 

auxiliary boilers (NTAB1, NTAB2) and 

emergency generator (NTEG); 

H) Net electrical output (MWh) for NT1; 

I) Operating hours for the emergency generator 

(NTEG); and 

J) All instances of deviations from Permit 

requirements. 

calendar year) 911.05 

18. Notification of Removal of Overfire Air: PSNH 

shall notify DES in writing within 30 calendar 

days of removing the overfire air capabilities. 

Within 30 calendar 

days of removal 

NT1 Env-A 910 (new) 

19. Prompt Reporting of Permit Deviations: The 

Permittee shall promptly report deviations from 

permit requirements by phone, fax or e-mail in 

accordance with Section XXVIII of this permit and 

Env-A 911 (new). 

Within 24 hours of 

discovery of 

occurrence 

Facility wide Env-A 911 (new) 

and 40 CFR 70.6 

(a)(3)(iii)(B) 

20. Certification by a Responsible Official: Any 

report or compliance certification submitted to the

DES and/or EPA shall contain certification by a 

responsible official of truth, accuracy, and 

completeness as outlined in Section XXI.B of this 

permit. 

With each submittal Facility wide 40 CFR 70.5 (d) 

21. Certification by the Designated Representative or 

the Alternate Designated Representative: Any 

document submitted under the Acid Rain program 

With each submittal NT1 40 CFR 72.21 
 PSNH Newington Page 57 

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Table 11 – Applicable Reporting Requirements 

Item 

No. 

Reporting Requirement Frequency of 

Reporting 

Applicable 

Emission Unit 

Regulatory 

Cite 

shall be signed and certified by the designated 

representative or the alternate designated 

representative and include the statements pursuant 

to 40 CFR 72.21 (a)(1) and (2). 

22. Emissions Reporting and Emissions Fees: The 

Permittee shall submit reports of actual emissions 

of all significant and insignificant activities and

payment of emission-based fees in accordance 

with Env-A 700 and Section XXIII of this permit. 

Quarterly payment 

on the 15th day of 

the 2nd quarter after 

actual emissions 

occurred; Reporting 

annually by April 

15th of the 

following year 

Facility wide Env-907.01 

(new) and Env-A 

705.03 and 

705.04 

23. Annual Acid Rain Compliance Certification 

Report: The Permittee shall submit an annual 

compliance certification report containing all the 

information required in 40 CFR 72.90(b) 

Annually, within 60 

days after the end 

of the calendar year 

NT1 40 CFR 72.90 

24. Multipollutant Budget and Trading Program 

Annual Compliance Certification: 

The Permittee shall submit an annual compliance 

certification for the prior year containing the 

information listed in Env-A 2913. 

By January 30 of 

each year, 

beginning in 2007 

NT1 Env-A 2913 

25. NOx Budget Program Compliance Certification: 

For each control period (May 1 to September 30 of 

each year), the Permittee shall submit an annual 

compliance certification containing the 

information listed in Env-A 3216. 

By November 30 of 

each year 

NT1 Env-A 3216 

26. Annual Title V Compliance Certification: The 

Permittee shall submit an annual compliance 

certification in accordance with Section XXI of 

this permit. 

Annually 

(no later than April 

15th of the 

following year) 

Facility wide 40 CFR 

70.6(c)(1) 

IX. Requirements Currently Not Applicable

The Permittee did not identify any requirements that are not applicable to the facility. 
 PSNH Newington Page 58 

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General Title V Operating Permit Conditions 

X. Issuance of a Title V Operating Permit

This Permit is issued in accordance with the provisions of Part Env-A 609. In accordance with 40 

CFR 70.6(a)(2), this Permit shall expire on the date specified on the cover page of this Permit, which

shall not be later than the date five (5) years after issuance of this Permit. 

Permit expiration terminates the Permittee's right to operate the Permittee's emission units, control 

equipment or associated equipment covered by this permit, unless a timely and complete renewal 

application is submitted at least 6 months before the expiration date. 

XI. Title V Operating Permit Renewal Procedures

Pursuant to Env-A 609.07(b), an application for renewal of this Permit shall be considered timely if 

it is submitted to the Director at least six months prior to the designated expiration date of this 

Permit. 

XII. Application Shield

Pursuant to Env-A 609.08, if an applicant submits a timely and complete application for the issuance 

or renewal of a Permit, the failure to have a Permit shall not be considered a violation of this part 

until the Director takes final action on the application. 

XIII. Permit Shield

A. Pursuant to Env-A 609.09(a), a permit shield shall provide that: 

1. For any applicable requirement or any state requirement found in the New Hampshire Rules 

Governing the Control of Air Pollution specifically included in this Permit, compliance with 

the conditions of this Permit shall be deemed compliance with said applicable requirement or 

said state requirement as of the date of permit issuance; and 

2. For any potential applicable requirement or any potential state requirement found in the New 

Hampshire Rules Governing the Control of Air Pollution specifically identified in this Title 

V Operating Permit Section IX as not applicable to the stationary source or area source, the 

Permittee need not comply with the specifically identified federal or state requirements. 

B. The permit shield identified in Section XIII.A. of this Permit shall apply only to those conditions 

incorporated into this Permit in accordance with the provisions of Env-A 609.09(b). It shall not 

apply to certain conditions as specified in Env-A 609.09(c) that may be incorporated into this 

Permit following permit issuance by DES. 
 PSNH Newington Page 59 

 TV-OP-054 

C. If a Title V Operating Permit and amendments thereto issued by the DES does not expressly 

include or exclude an applicable requirement or a state requirement found in the NH Rules 

Governing the Control of Air Pollution, that applicable requirement or state requirement shall not 

be covered by the permit shield and the Permittee shall comply with the provisions of said 

requirement to the extent that it applies to the Permittee. 

D. If the DES determines that this Title V Operating Permit was issued based upon inaccurate or 

incomplete information provided by the applicant or Permittee, any permit shield provisions in 

said Title V Operating Permit shall be void as to the portions of said Title V Operating Permit 

which are affected, directly or indirectly, by the inaccurate or incomplete information. 

E. Pursuant to Env-A 609.09(f), nothing contained in Section XIII of this Permit shall alter or affect 

the ability of the DES to reopen this Permit for cause in accordance with Env-A 609.19 or to 

exercise its summary abatement authority. 

F. Pursuant to Env-A 609.09(g), nothing contained in this section or in any title V operating permit 

issued by the DES shall alter or affect the following: 

1. The ability of the DES to order abatement requiring immediate compliance with applicable 

requirements upon finding that there is an imminent and substantial endangerment to public 

health, welfare, or the environment; 

2. The state of New Hampshire's ability to bring an enforcement action pursuant to RSA 125-

C:15,II; 

3. The provisions of section 303 of the CAA regarding emergency orders including the authority 

of the EPA Administrator under that section; 

4. The liability of an owner or operator of a source for any violation of applicable requirements 

prior to or at the time of permit issuance; 

5. The applicable requirements of the acid rain program, consistent with section 408(a) of the 

CAA; 

6. The ability of the DES or the EPA Administrator to obtain information about a stationary 

source, area source, or device from the owner or operator pursuant to section 114 of the 

CAA; or 

7. The ability of the DES or the EPA Administrator to enter, inspect, and/or monitor a stationary 

source, area source, or device. 

XIV. Reopening for Cause

The Director shall reopen and revise a Title V Operating Permit for cause if any of the circumstances 

contained in Env-A 609.19(a) exist. In all proceedings to reopen and reissue a Title V Operating 

Permit, the Director shall follow the provisions specified in Env-A 609.19(b) through (g). 
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XV. Administrative Permit Amendments

A. Pursuant to Env-A 612.01, the Permittee 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). 

XVI. Operational Flexibility

A. Pursuant to Env-A 612.02, the Permittee subject to and operating under this Title V Operating 

Permit may make changes involving trading of emissions, off-permit changes, and section 

502(b)(10) changes at the permitted stationary source or area source without filing a Title V 

Operating Permit application for and obtaining an amended Title V Operating Permit, provided 

that all of the following conditions are met, as well as conditions specified in Section XVI. B 

through E of this permit, as applicable. DES has included permit terms authorizing the generation 

of DERs. 

1. The change is not a modification under any provision of Title I of the CAA; 

2. The change does not cause emissions to exceed the emissions allowable under the Title V 

operating permit, whether expressed therein as a rate of emissions or in terms of total 

emissions; 

3. The owner or operator has obtained any temporary permit required by Env-A 600; 

4. The owner or operator has provided written notification to the director and administrator of 

the proposed change and such written notification includes: 

a) The date on which each proposed change will occur or has occurred; 

b) A description of each such change; 

c) Any change in emissions that will result; 

d) A request that the operational flexibility procedures be used; and 

e) The signature of the responsible official, consistent with Env-A 605.04; 

5. The change does not exceed any emissions limitations established under any of the 

following: 

a) The New Hampshire Code of Administrative Rules, Env-A 100-4300; 
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b) The CAA; or 

c) This Title V Operating Permit; and 

6. The Permittee, DES, and EPA have attached each written notice required above to their copy 

of this Title V Operating Permit. 

B. For changes involving the trading of emissions, the Permittee must also meet the following 

conditions: 

1. The Title V Operating Permit issued to the stationary source or area source already contains 

terms and conditions including all terms and conditions which determine compliance 

required under 40 CFR 70.6(a) and (c) and which allow for the trading of emissions 

increases and decreases at the permitted stationary source or area source solely for the 

purpose of complying with a federally-enforceable emissions cap that is established in the 

permit independent of otherwise applicable requirements; 

2. The owner or operator has included in the application for the Title V Operating Permit 

proposed replicable procedures and proposed permit terms which ensure that the emissions 

trades are quantifiable and federally enforceable for changes to the Title V Operating Permit 

which qualify under a federally- enforceable emissions cap that is established in the Title V 

Operating Permit independent of the otherwise applicable requirements; 

3. The Director has not included in the emissions trading provision any devices for which 

emissions are not quantifiable or for which there are no replicable procedures to enforce 

emissions trades; and 

4. The written notification required above is made at least 7 days prior to the proposed change 

and includes a statement as to how any change in emissions will comply with the terms and 

conditions of the Title V Operating Permit. 

C. For off-permit changes, the Permittee must also meet the following conditions: 

1. Each off-permit change meets all applicable requirements and does not violate any existing 

permit term or condition; 

2. The written notification required above is made contemporaneously with each off-permit 

change, except for changes that qualify as insignificant under the provisions of Env-A 

609.04; 

3. The change is not subject to any requirements under Title IV of the CAA and the change is 

not a Title I modification; 

4. The Permittee keeps a record describing the changes made at the source which result in 

emissions of a regulated air pollutant subject to an applicable requirement, but not otherwise 
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regulated under this Permit, and the emissions resulting from those changes; and 

5. The written notification required above includes a list of the pollutants emitted and any 

applicable requirement that would apply as a result of the change. 

D. For section 502(b)(10) changes, the Permittee must also meet the following conditions: 

1. The written notification required above is made at least 7 days prior to the proposed change; 

and 

2. The written notification required above includes any permit term or condition that is no 

longer applicable as a result of the change. 

E. Pursuant to Env-A 612.02(f), the off-permit change and section 502(b)(10) change shall not 

qualify for the permit shield under Env-A 609.09. 

XVII. Minor Permit Amendments

A. Pursuant to Env-A 612.05 prior to implementing a minor permit modification, the Permittee shall 

submit a written request to the Director in accordance with the requirements of Env-A 612.05(b). 

B. The Director shall take final action on the minor permit amendment request in accordance with 

the provisions of Env-A 612.05(c) through (g). 

C. Pursuant to Env-A 612.05(h), the permit shield specified in Env-A 609.09 shall not apply to 

minor permit amendments under Section XVII. of this Permit. 

D. Pursuant to Env-A 612.05(a), the Permittee shall be subject to the provisions of RSA 125-C:15 if 

the change is made prior to the filing with the Director a request for a minor permit amendment. 

XVIII. Significant Permit Amendments

A. Pursuant to Env-A 612.06, a change at the facility shall qualify as a significant permit 

amendment if it meets the criteria specified in Env-A 612.06(a)(1) through (5). 

B. Prior to implementing the significant permit amendment, the Permittee shall submit a written 

request to the Director which includes all the information as referenced in Env-A 612.06(b) and 

(c) and shall be issued an amended Title V Operating Permit from the DES. The Permittee shall 

be subject to the provisions of RSA 125-C:15 if a request for a significant permit amendment is 

not filed with the Director and/or the change is made prior to the issuance of an amended Title V 

Operating Permit. 

C. The Director shall take final action on the significant permit amendment in accordance with the 

Procedures specified in Env-A 612.06(d), (e) and (f). 
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XIX. Title V Operating Permit Suspension, Revocation or Nullification

A. Pursuant to RSA 125-C:13, the Director may suspend or revoke any final permit issued 

hereunder if, following a hearing, the Director determines that: 

1. The Permittee has committed a violation of any applicable statute or state requirement found 

in the New Hampshire Rules Governing the Control of Air Pollution, order or permit 

condition in force and applicable to it; or 

2. The emissions from any device to which this Permit applies, alone or in conjunction with 

other sources of the same pollutants, presents an immediate danger to the public health. 

B. The Director shall nullify any Permit, if following a hearing in accordance with RSA 541-A:30, 

II, a finding is made that the Permit was issued in whole or in part based upon any information 

proven to be intentionally false or misleading. 

XX. Inspection and Entry

EPA and DES personnel shall be granted access to the facility covered by this Permit, in accordance 

with RSA 125-C:6,VII, for the purposes of: inspecting the proposed or permitted site; investigating a 

complaint; and assuring compliance with any applicable requirement or state requirement found in 

the NH Rules Governing the Control of Air Pollution and/or conditions of any Permit issued 

pursuant to Chapter Env-A 600. 

XXI. Certifications

A. Compliance Certification Report 

In accordance with 40 CFR 70.6(c) the Responsible Official shall certify, for the previous 

calendar year, that the facility is in compliance with the requirements of this permit. The report 

shall be submitted annually, no later than April 15th of the following year. The report shall be 

submitted to the DES and to the U.S. Environmental Protection Agency - New England Region.

The report shall be submitted in compliance with the submission requirements below. 

 In accordance with 40 CFR 70.6(c)(5), the report shall describe: 

1. The terms and conditions of the Permit that are the basis of the certification; 

2. The current compliance status of the source with respect to the terms and conditions of this 

Permit, and whether compliance was continuous or intermittent during the reporting period; 

3. The methods used for determining compliance, including a description of the monitoring, 

record keeping, and reporting requirements and test methods; and 

4. Any additional information required by the DES to determine the compliance status of the 

source. 
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B. Certification of Accuracy Statement

All documents submitted to the DES shall contain a certification of accuracy statement by the 

responsible official of truth, accuracy, and completeness. Such certification shall be in 

accordance with the requirements of 40 CFR 70.5(d) and contain the following language: 

"I am authorized to make this submission on behalf of the facility for 

which the submission is made. Based on information and belief formed 

after reasonable inquiry, I certify that the statements and information in the 

enclosed documents are to the best of my knowledge and belief true, 

accurate and complete. I am aware that there are significant penalties for 

submitting false statements and information or omitting required 

statements and information, including the possibility of fine or 

imprisonment." 

All reports submitted to DES (except those submitted as emission based fees as outlined in 

Section XXIII of this Permit) 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: Section Supervisor, Compliance Bureau 

All reports submitted to EPA shall be submitted to the following address: 

Office of Environmental Stewardship 

Director Air Compliance Program 

United States Environmental Protection Agency 

1 Congress Street 

Suite 1100 (SEA) 

Boston, MA 02114-2023 

ATTN: Air Compliance Clerk 
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XXII. Enforcement

Any noncompliance with a permit condition constitutes a violation of RSA 125-C:15, and, as to the 

conditions in this permit which are federally enforceable, a violation of the Clean Air Act, 42 U.S.C.

Section 7401 et seq., and is grounds for enforcement action, for permit termination or revocation, or 

for denial of an operating permit renewal application by the DES and/or EPA. Noncompliance may 

also be grounds for assessment of administrative, civil or criminal penalties in accordance with RSA 

125-C:15 and/or the Clean Air Act. This Permit does not relieve the Permittee from the obligation to 

comply with any other provisions of RSA 125-C, the New Hampshire Rules Governing the Control 

of Air Pollution, or the Clean Air Act, or to obtain any other necessary authorizations from other 

governmental agencies, or to comply with all other applicable Federal, State, or Local rules and 

regulations, not addressed in this Permit. 

In accordance with 40 CFR 70.6 (a)(6)(ii) a Permittee shall not claim as a defense in an enforcement 

action that it would have been necessary to halt or reduce the permitted activity in order to maintain

compliance with the conditions of this Permit.

XXIII. Emission-Based Fee Requirements

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

calendar year pursuant to Env-A 705.03. 

B. The Permittee shall determine the total actual quarterly emissions from the facility to be included 

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

accordance with the methods specified in Env-A 616.

C. The Permittee shall calculate the quarterly 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 quarterly emission-based fee for each calendar quarter as specified in Env-A 

705. 

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

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 Permittee shall contact the DES each calendar year for the value of the Inventory 

Stabilization Factor. 

FEE * E = DPT * CPIm* ISF
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E. The Permittee shall contact the DES each calendar year for the value of the Consumer Price 

Index Multiplier. 

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

calculations referenced in Sections XXIII.B. and C of this Permit for each calendar quarter. 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., fees for emissions occurring during January, 

February, March 2007 are due July 15, 2007); 

2. October of the year to which the fee applies (e.g., fees for emissions occurring during April, 

May, June 2007 are due on October 15, 2007); 

3. January of the following year (e.g., fees for emissions occurring during July, August, 

September 2007 are due on January 15, 2008); 

4. April of the following year (e.g., fees for emissions occurring during October, November, 

December 2007 are due on April 15, 2008). 

The Permittee shall pay any remaining balance of the total emission-based fee for the year 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 Permittee of any under payments or over payments of the annual 

emission-based fee in accordance with Env-A 705.05.

XXIV. Duty To Provide Information

In accordance with 40 CFR 70.6 (a)(6)(v), upon the DES's written request, the Permittee shall 

furnish, within a reasonable time, any information necessary for determining whether cause exists for 

modifying, revoking and reissuing, or terminating the Permit, or to determine compliance with the 

Permit. Upon request, the Permittee shall furnish to the DES copies of records that the Permittee is 

required to retain by this Permit. The Permittee may make a claim of confidentiality as to any 

information submitted pursuant to this condition in accordance with Part Env-A 103 at the time such 

information is submitted to DES. DES shall evaluate such requests in accordance with the 

provisions of Part Env-A 103. 
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XXV. Property Rights

Pursuant to 40 CFR 70.6 (a)(6)(iv), this Permit does not convey any property rights of any sort, or 

any exclusive privilege. 

XXVI. Severability Clause

Pursuant to 40 CFR 70.6 (a)(5), the provisions of this Permit are severable, and if any provision of 

this Permit, or the application of any provision of this Permit to any circumstances is held invalid, 

the application of such provision to other circumstances, and the remainder of this Permit, shall not 

be affected thereby. 

XXVII. Emergency Conditions

Pursuant to 40 CFR 70.6 (g), the Permittee shall be shielded from enforcement action brought for 

noncompliance with technology based20 emission limitations specified in this Permit as a result of an 

emergency

21. In order to use emergency as an affirmative defense to an action brought for 

noncompliance, the Permittee shall demonstrate the affirmative defense through properly signed, 

contemporaneous operating logs, or other relevant evidence that: 

A. An emergency occurred and that the Permittee can identify the cause(s) of the emergency; 

B. The permitted facility was at the time being properly operated; 

C. During the period of the emergency, the Permittee took all reasonable steps as expeditiously as 

possible, to minimize levels of emissions that exceeded the emissions standards, or other 

requirements in this Permit; and 

D. The Permittee submitted notice of the emergency to the DES within two (2) business days of the 

time when emission limitations were exceeded due to the emergency. This notice must contain a 

description of the emergency, any steps taken to mitigate emission, and corrective actions taken. 

 

 

20

 Technology based emission limits are those established on the basis of emission reductions achievable with 

various control measures or process changes (e.g., a new source performance standard) rather than those established 

to attain health based air quality standards. 

 

21

 An "emergency" means any situation arising from sudden and reasonably unforeseeable events beyond the 

control of the source, including acts of God, which situation would require immediate corrective action to restore 

normal operation, and that causes the source to exceed a technology based limitation under the permit, due to 

unavoidable increases in emissions attributable to the emergency. An emergency shall not include noncompliance to 

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

operations, operator error or decision to keep operating despite knowledge of any of these things.
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XXVIII. Permit Deviation 

In accordance with 40 CFR 70.6(a)(3)(iii)(B), the Permittee 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 Permittee 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 Section XXVII of this Permit. 

Reporting a Permit deviation is not an affirmative defense for action brought for noncompliance. 
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Federal Acid Rain Requirements 

XXIX. Phase II Acid Rain Permit Application

The attached Phase II Acid Rain Permit application, dated January 12, 2004, is hereby incorporated 

by reference into this permit. The Permittee shall comply with the requirements set forth in the 

Phase II Acid Rain Permit Application and this permit. 

XXX. General Acid Rain Provisions

The Permittee shall comply with the applicable provisions of 40 CFR 72, Permit Regulations; 40 

CFR 73, Sulfur Dioxide Allowance System; 40 CFR 75, Continuous Emission Monitoring; and 40 

CFR 77, Excess Emissions.