### STATE OF NEW HAMPSHIRE Department of Environmental Services Air Resources Division 

# Temporary Permit

Permit No: TP-0008 Date Issued: March 9, 2009

This certifies that:

Northeast Utilities Public Service of New Hampshire 780 North Commercial Street Manchester, NH 03101

has been granted a Temporary Permit for a

Flue Gas Desulphurization System

at the following facility and location:

Public Service of New Hampshire Merrimack Station 97 River Rd. Bow, NH 03304-3314

Facility ID No: 3301300026 Application No: FY07-0103

which includes devices that emit air pollutants int o the ambient air as set forth in the permit applic ation referenced above which was filed with the New Hamps hire Department of Environmental Services, Air Resources Division (Division) in accordance with RS A 125-C of the New Hampshire Laws. Request for per mit renewal is due to the Division at least 90 days pri or to expiration of this permit and must be accompa nied by the appropriate permit application forms.

This permit is valid upon issuance and expires on September 30, 2010

.

__________________________________
Director, Air Resources Division

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## TABLE OF CONTENTS

ABBREVIATIONS......................................

................................................... ................................................... ... 3

FACILITY SPECIFIC TEMPORARY PERMIT CONDITIONS ......

................................................... ......... 5

I. F ACILITY 

### D ESCRIPTION OF 

### O PERATIONS



### ................................................... .................................................. 5 II. P ROJECT 

### D ESCRIPTION



### ................................................... ................................................... ......................... 5 III. P ERMITTED 

### A CTIVITIES



### ................................................... ................................................... ........................ 6 IV. S IGNIFICANT 

### A CTIVITIES 

### I DENTIFICATION AND 

### S TACK 

### C RITERIA



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

................................................... ........................................ 6 B. Stack Criteria .....................................

................................................... ................................................. 7 V. P OLLUTION 

### C ONTROL 

### E QUIPMENT 

### /M ETHOD 

### I DENTIFICATION



### ................................................... ................. 7 VI. A PPLICABLE 

### R EQUIREMENTS



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

................................................... ................................ 8 B. Initial Compliance Demonstration Requirements......

................................................... ....................... 13 C. Monitoring/Testing Requirements....................

................................................... ................................. 15 D. Recordkeeping Requirements.........................

................................................... ................................... 18 E. Reporting Requirements.............................

................................................... ....................................... 20 VII. A DMINISTRATIVE 

### P ERMIT 

### A MENDMENTS



### ................................................... .............................................. 21 VIII. M INOR 

### P ERMIT 

### A MENDMENTS



### ................................................... ................................................... ........... 21 IX. S IGNIFICANT 

### P ERMIT 

### A MENDMENTS



### ................................................... ................................................... ... 21 X. E MISSION 

### -B ASED 

### F EE 

### R EQUIREMENTS



### ................................................... .................................................. 2 2 XI. P ERMIT 

### D EVIATION



### ................................................... ................................................... ............................ 24

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## ABBREVIATIONS AAL Ambient Air Limit AEL Alternative Emission Limit AP-42 Compilation of Air Pollutant Emission Factors ARD Air Resources Division ASTM American Society for Testing and Materials ATS Allowance Tracking System BACT Best Available Control Technology BHP (or bhp) Brake Horse Power BTU British Thermal Units CAA Clean Air Act, 42 U.S.C. § 7401, et seq. CAM Compliance Assurance Monitoring CAS Chemical Abstracts Service CEMS Continuous Emission Monitoring System CFR Code of Federal Regulations CNG Compressed Natural Gas CO Carbon Monoxide CO 2 

### Carbon Dioxide COMS Continuous Opacity Monitoring System CTM Conditional Test Method DES New Hampshire Department of Environmental Servi ces DER Discrete Emission Reduction Env-A New Hampshire Code of Administrative Rules – Air Resources Division Env-Wm New Hampshire Code of Administrative Rules – Waste Management Division ECS Emission Control System ERC Emission Reduction Credit ETS Emissions Tracking System FGD Flue Gas Desulphurization gal/hr Gallons per hour HAP Hazardous Air Pollutant HHV High Heat Value HCl Hydrochloric acid hr Hour kscfm 1,000 standard cubic feet per minute kGal 1,000 gallons KVDC Kilovolt Direct Current KW Kilowatt LAER Lowest Achievable Emission Rate lb/hr Pounds per hour LNB Low NO x 

### Burner LNG Liquid Natural Gas LPG Liquid Petroleum Gas (Propane) MACT Maximum Achievable Control Technology mmBtu Million British Thermal Units MMCF Million Cubic Feet MW Megawatt

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## ABBREVIATIONS (cont.)

NAAQS National Ambient Air Quality Standard NG Natural Gas NHDES (or DES) New Hampshire Department of Environm ental Services NMOC Non-Methane Organic Compound NO x 

### Oxides of Nitrogen NSPS New Source Performance Standard NSR New Source Review PM Particulate Matter PM 10 

### Particulate Matter less than 10 microns diameter ppm part per million ppmdv part per million by dry volume PSD Prevention of Significant Deterioration PSI Pounds per Square Inch PTE Potential to Emit RACT Reasonably Available Control Technology RTAP Regulated Toxic Air Pollutant SIP State Implementation Plan SO 2 

### Sulfur Dioxide TSP Total Suspended Particulate Matter TPY Tons per Year USEPA United States Environmental Protection Agency VOC Volatile Organic Compound

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## Facility Specific Temporary Permit Conditions

I. Facility Description of Operations

Public Service of New Hampshire - Merrimack Station is a fossil fuel-fired electricity generating facility, owned and operated by Public Service of N ew Hampshire (PSNH), a subsidiary of Northeast Utilities. The facility is comprised of two utilit y boilers, two combustion turbines operating as loa d shaving units, an emergency generator, an emergency boiler, and coal handling systems including primary and secondary coal crushers, coal piles, co al conveyor systems, and coal unloading from railcars. The facility operations also include var ious activities that are classified as insignifican t or exempt activities.

The two utility boilers (MK1 and MK2) primarily bur n bituminous coal, the two combustion turbines primarily burn No. 1 fuel oil or JP-4, the emergency generator burns No. 2 fuel oil or diesel fuel, and the emergency boiler burns No. 2 fuel oil or diesel fuel. PSNH – Merrimack Station ignites the utility boilers with No. 2 fuel oil.

Each boiler stack is equipped with continuous emiss ions monitoring systems (CEMS) and a continuous opacity monitoring system (COMS). PSNH – Merrimack Station has installed control equipment and implemented operational changes to re duce emissions, including trials of low sulfur coals to control sulfur dioxide (SO 2 

### ) emissions, selective catalytic reduction (SCR) sy stems to control nitrogen oxide (NO x 

### ) emissions, and electrostatic precipitators (ESP) to control particulate matter (PM) emissions. PSNH has also initiated mer cury reduction trials including carbon injection and the use of low mercury coals.

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

II. Project Description

The Owner has filed a Temporary Permit application requesting to install a wet, limestone-based flue gas desulphurization (FGD) system to control mercur y emissions from Electric Generating Units MK1 and MK2. The FGD system will also provide a co -benefit by removing sulfur dioxide emissions. The application was filed in accordance with RSA 125-O:13,I, which requires this facility to file an initial permit application by J une 8, 2007. This permit establishes limits on mercury and sulfur dioxide emissions based on the r equirements of RSA 125-O:13 and 40 CFR 51.308, respectively. This permit also contains ap plicable monitoring, performance testing, recordkeeping and reporting requirements for the pu rpose of ensuring that the facility can comply with the requirements of RSA 125-O:13 and 40 CFR 51 .308. Once the FGD system is constructed and operational, initial stack testing on MK1 and MK2 will be used to (1) determine whether the facility complies with the applicable mercury and sulfur dioxide limits; and (2) to establish any necessary operatin g parameters to ensure that the mercury and sulfur dioxide limits will be met on an ongoing basis. Pe riodic stack testing and/or continuous emission monitors will be used to verify that the parameters used to monitor and control mercury and sulfur dioxide emissions continue to be valid.

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The facility currently operates under the applicati on shield provisions of Env-A 609.08, Application Shield and in accordance with permits FP-T-0054 (MK1), TP -B-0462 (MK2), PO-B-0034 (CT1), PO-B-0035 (CT2), PO-B-1788 (Emergency Generator), T P-B-0490 (Emergency Boiler), PO-B-2416 (Primary Coal Crusher) and PO-B-2417 (Secondary Coa l Crusher), which are currently in the process of being streamlined into a Title V Operati ng Permit. These previously issued permits will be referenced as “Previous Permits” throughout this document. This Temporary Permit includes new conditions associated with this project, and wh ere necessary, identifies conditions of the Previous Permits that will either be modified or su perseded as a result of this project. All terms an d conditions of the Previous Permits not specifically identified in this permit remain in effect unchanged. Upon issuance of this permit, the Owner shall comply with all unchanged terms and conditions of the Previous Permits and all terms an d conditions of this permit.

III. Permitted Activities

In accordance with all of the applicable requiremen ts identified in this permit, the Owner is authorized to operate the devices and or processes identified in Sections IV and V within the terms and conditions specified in this Permit.

IV. Significant Activities Identification and Stack Cri teria

A. Significant Activity Identification

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

Table 1 - Significant Activity Identification Emission Unit Number Description of

Emission Unit Maximum Gross Heat Input Rating Maximum Operating Conditions

MK1 Steam Generating

Unit 1 (Installed in 1960) Front wall firing Bituminous Coal: 1,238

MMBtu/hr a. Maximum fuel consumption rate of bituminous c oal shall be limited to 48.5 tons/hr, not to exceed 425,289 tons during any consecutive 12 month period 1

. b. No. 2 fuel oil consumption shall be limited to 1,656 gallons per hour, not exceed 14.5 million gallons during any consecutive 12 month period 2

. MK2 Steam Generating

Unit 2 (Installed in 1968) Opposed wall firing Bituminous Coal: 3,473

MMBtu/hr a. Maximum fuel consumption rate of bituminous coal shall be limited to 136.2 tons/hr, not to exceed 1,193,078 tons during any consecutive 12 month period 3

. b. No. 2 fuel oil consumption shall be limited to 1,65 6 gallons per hour, not exceed 14.5 million gallons during any consecutive 12 month period 4

.

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

2 No. 2 fuel oil is used to ignite individual fires before establishing the main coal fires. The heati ng value of No. 2 fuel oil is assumed to be 140,000 Btu/gal. The fuel consumption limits may vary based on the actual heat content of the f uel burned.

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

4 No. 2 fuel oil is used to ignite individual fires before establishing the main coal fires. The heati ng value of No. 2 fuel oil is assumed to be 140,000 Btu/gal. The fuel consumption limits may vary based on the actual heat content of the f uel burned.

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Table 1 - Significant Activity Identification Emission Unit Number Description of

Emission Unit Maximum Gross Heat Input Rating Maximum Operating Conditions

MKLC1 Limestone

Processing and Handling System Not Applicable Limestone processing rate of the wet limestone ball mills of less than 25 tons per hour 5

.



### B. Stack Criteria

The following devices at the Facility shall have ex haust stacks that discharge vertically, without obstruction, and meet the criteria in Table 2:

Table 2 – Stack Criteria Stack Number Emission

Unit Number Emission Unit

Description Minimum Stack

Height (Feet) Above Ground Level Maximum Inside

Stack Diameter (Feet) STMK2 (Bypass Stack) MK1 Steam Generating Unit

No. 1 317 14.5

STMK3 MK1

and/or MK2 with MK2-PC7 Steam Generating Units

No. 1 and/or No. 2 with FGD System 445 21.5



### 1. The Owner may change the stack criteria described i n Table 2 with notification to DES provided that:

i. An air quality impact analysis is performed either by the facility or DES (if requested by the facility in writing) in accordance with Env-A 606 and the “Guidance and Procedure for Performing Air Quality Impact Modeling in New Hampshire,” and ii. The analysis demonstrates that emissions from the m odified stack will continue to comply with all applicable emission limitations and ambient air limits.

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

V. Pollution Control Equipment/Method Identification

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

5 Only one wet ball mill will be operated at a time. The second wet ball mill serves as a backup unit.

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Table 3 – Pollution Control Equipment/Method Identi fication Pollution Control Equipment Number Description of Equipment/Method Emission Unit Number Controlled

MK1-PC1 Electrostatic Precipitator (ESP) #1 on MK1 MK1 MK1-PC2 ESP #2 on MK1 MK1 MK1-PC3 Selective Catalytic Reduction (SCR) deNO x System MK1 MK2-PC4 ESP #1 on MK2 MK2 MK2-PC5 ESP #2 on MK2 MK2 MK2-PC6 SCR deNO x System MK2 MK2-PC7 Flue Gas Desulphurization (FGD) System MK1 and MK2



### VI. Applicable Requirements

A. Operational and Emission Limitations The Owner shall be subject to the operational and e mission limitations identified in Table 4 below.

Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

1. Env-A 1403 Devices subject to RSA 125-I and Env-A 1400 Devices or processes, subject to RSA 125-I and Env- A 1400, shall

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

2. Env-A 1403.01(d) Devices subject to RSA 125-I and Env-A 1400 Documentation for the demonstration of compliance s hall be retained and

shall be made available to DES for inspection upon request.

3. Env-A 1404.01 Devices subject to RSA 125-I and Env-A 1400 a. The Owner of a new or modified device or process re quiring 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 oper ate the device or process until a temporary permit is issued. 4. Env-A 1405.01 Devices subject to RSA 125-I and Env-A 1400 The Owner of any device or process that emits an RT AP shall determine

compliance with the AAL by using one of the methods provided in EnvA 1405. Upon request, the Owner of any device or p rocess that emits an RTAP shall provide documentation of compliance with the AAL to DES.

5. Env-A 1002.04 Fugitive Dust MKLC1 The Owner shall prevent, abate, and control f ugitive dust emissions using best management practices 6

.

6 To comply with this provision, PSNH – Merrimac k Station shall use Best Management Practices to ma nage and minimize fugitive dust, as established in the PSNH Merrimack Station Environmental Management System Plan for Fugitive E missions.

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Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

6. 40 CFR 51.308(e)(1) MK2 a. Beginning on July 1, 2013, when MK2-PC7 (FGD system ) is in operation, SO 2 emissions shall be controlled to 10 percent of the uncontrolled SO 2 emission rate (90 percent SO 2 removal). Compliance with this percent reduction shall be det ermined on a calendar month average by comparing the SO 2 emission rates as measured by CEMS on the inlet and outlet of the FGD system. b. The Owner shall submit a report no later than Decem ber 31, 2014 that includes the calendar month average SO 2 emission rates at the inlet and outlet of the FGD and the corresponding calenda r month average emissions reductions during the preceding 12 months of operation, excluding the initial startup and commissioning per iod and any periods when the FGD system is not operating. DES will use this data to establish the maximum sustainable rate of SO 2 emissions reductions for MK2. The maximum sustainable rate is the highe st rate of reductions that can be achieved 100 percent of the time.

c. DES shall establish the maximum sustainable rate of SO 2 emissions reductions based on a statistical analysis of the d ata submitted to DES pursuant to paragraph b. above. This established r ate shall be incorporated as a permit condition for MK2. Under no circumstances shall the SO 2 removal efficiency for MK2 be less than 90 percent

. 7. 40 CFR 51.308(e)(1) MK2 Beginning on July 1, 2013, the Owner shall not operate MK2 unless MK2-PC7 is in operation. 8. 40 CFR 51.308 Regional Haze Plan MK1 a. Beginning on July 1, 2013, when MK2-PC7 (FG D system) is in operation, SO 2 emissions shall be controlled to 10 percent of the uncontrolled SO 2 emission rate (90 percent SO 2 removal). Compliance with this percent reduction shall be det ermined on a calendar month average by comparing the SO 2 emission rates as measured by CEMS on the inlet and outlet of the FGD system. b. The Owner shall submit a report no later than D ecember 31, 2014 that includes the calendar month average SO 2 emission rates at the inlet and outlet of the FGD and the corresponding calenda r month average emissions reductions during the preceding 12 months of operation, excluding the initial startup and commissioning per iod and any periods when the FGD system is not operating. DES will use this data to establish the maximum sustainable rate of SO 2 emissions reductions for MK1. The maximum sustainable rate is the highe st rate of reductions that can be achieved 100 percent of the time. c. DES shall establish the maximum sustainable rat e of SO 2 emissions reductions based on a statistical analysis of the d ata submitted to DES pursuant to paragraph b. above. This established r ate shall be incorporated as a permit condition for MK1. Under no circumstances shall the SO 2 removal efficiency for MK1 be less than 90 percent

. 9. 40 CFR 51.308 MK1 Beginning on July 1, 2013, the Ow ner shall not operate MK1 through STMK2 (bypass stack) if MK2-PC7 is capable of stabl e operation. 10. 40 CFR 51.308 MK1 Beginning on July 1, 2013, the Ow ner shall not operate MK1 through STMK2 (bypass stack) for more than 840 hours in any consecutive 12- month period.

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Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

11. Env-A 1606.01(a)(1) MK1 & MK2 For coal burning devi ces placed in operation before April 15, 1970, the sulfur content of the coal shall not exceed 2.8 pou nds per million BTU gross heat content at any time. 12. Env-A 1606.01(a)(2) MK1 & MK2 For coal burning devi ces placed in operation before April 15, 1970, the sulfur content of the coal shall not exceed 2.0 pou nds per million BTU gross heat content averaged over any consecutive 3- month period. 13. RSA 125-O:13, II Affected Sources as defined in RSA 125- O:12 Beginning on July 1, 2013, total mercury emissions from the affected

sources shall be at least 80 percent less on an ann ual basis than the baseline mercury input, as defined in RSA 125-O:12, III.

14. RSA 125-O:13, III MK1 & MK2 Prior to July 1, 2013, the Owner shall test and implement, as practicable, mercury reduction control technologies or methods t o achieve early reductions in mercury emissions below the baseline mercury emissions. The Owner shall report the results of any testing t o DES and shall submit a plan for DES approval before commencing implement ation.

15. RSA 125-O:13-V MK1 & MK2 a. Mercury reductions (achieved through the operation of the FGD system) greater than 80 percent shall be sustained insofar as the proven operational capability of the system, as ins talled, allows. b. DES, in consultation with the Owner, shall determin e the maximum sustainable rate of mercury emissions reductions an d incorporate such rate as a permit condition for MK1 and MK2. This re quirement in no way affects the ability of the Owner to earn over-c ompliance credits consistent with RSA 125-O:16, II. 16. RSA 125-O:13, VI MK1 & MK2 The purchase of mercury emissions allowances or credits from any established emissions allowance or credit program s hall not be allowed for compliance with the mercury reduction requireme nts of this permit or the requirements of RSA 125:O:13. 17. RSA 125-O:13, VII MK1 & MK2 If the mercury reductio n requirement in Item 13 above is not achieved in any year after the July 1, 2013 implementation date , and after full operation of the FGD technology, then the Owner may utilize early emissions reduction credits or over-compliance cred its, or both, to make up any shortfall, and thereby be in compliance.

18. RSA 125-O:13, VIII MK1 & MK2 If the mercury reducti on requirement in Item 13 above is not achieved by the Owner in any year after the July 1, 2013 implem entation date despite the Owner's installation and full operation of FGD technology, consistent with good operational practice, and the owner's exh austion of any available early emissions reduction or over-complia nce credits, then the owner shall be deemed in violation of this section unless it submits a plan to DES, within 30 days of such noncompliance, and s ubsequently obtains approval of that plan for achieving compliance with in one year from the date of such noncompliance. DES may impose conditio ns for approval of such plan.

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Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

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

a. The Owner may request a variance from the mercury e missions reduction requirements of this permit and RSA 125-O :13, by submitting a written request to DES. The request sh all provide sufficient information concerning the conditions or special circumstances on which the variance request is base d to demonstrate to the satisfaction of DES that variance from the a pplicable requirements is necessary. b. Where an alternative schedule is sought, the Owner shall submit a proposed schedule which demonstrates reasonable fur ther progress and contains a date for final compliance as soon as practicable. If DES deems such a delay is reasonable under the cite d circumstances, it shall grant the requested variance.

c. Where an alternative reduction requirement is sough t, the Owner shall submit information to substantiate an energy supply crisis, a major fuel disruption, an unanticipated or unavoida ble disruption in the operations of the affected sources, or technolo gical or economic infeasibility. DES, after consultation with the New Hampshire Public Utilities Commission, shall grant or deny the reque sted variance. If requested by the Owner, DES shall provide the owner with an opportunity for a hearing on the request. 20. RSA 125-O:16, I MK1 & MK2 Economic Performance Ince ntives/Generation and Use of Early Emissions Reduction Credits:

a. DES shall issue to the Owner early emissions reduct ion credits in the form of credits or fractions thereof for each pound of mercury or fraction thereof reduced below the baseline mercury emissions, on an annual basis, in the period prior to July 1, 2013.

b. Ratios of early reductions credits to pounds of mer cury reduced shall be as follows:

i. 1.5 credits per pound reduced prior to July 1, 2008 ; ii. 1.25 credits per pound for reductions between July 1, 2008 and December 31, 2010; and iii. 1.1 credits per pound for reductions between Januar y 1, 2011 and July 1, 2013.

c. Reductions shall be calculated based upon the resul ts of stack tests conducted, measurement by continuous emission monit oring, or other methodology approved by DES to confirm emissions du ring the time of operation of mercury reduction technology.
d. Early emissions reduction credits may be banked by the Owner or utilized after July 1, 2013 to meet the reduction r equirement of RSA 125-O:13, II as allowed under RSA 125-O:13, VII.

e. Early emissions reduction credits are not sellable or transferable to non-affected sources; however, upon the July 1, 201 3 compliance date, the Owner may request a one-for-one conversio n of early emissions reduction credits to over-compliance cred its.

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Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

f. Should a federal rule applicable to mercury emissio ns at one or more of the affected sources be enacted with an implemen tation date prior to July 1, 2013, then early reduction credits may o nly be earned for emissions reductions that exceed the level required by the federal rule of the affected sources in aggregate or the baselin e mercury emissions level, whichever is lower, at the same ratios liste d in subparagraph (b) above.

g. Early emissions reduction credits shall not be used for compliance with the requirement of RSA 125-O:13, II prior to t he installation of FGD technology, and shall not be used as a means to delay the installation of the FGD technology.

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

a. DES shall issue to the Owner over-compliance credit s in the form of credits or fractions thereof for each pound of merc ury or fraction thereof reduced in excess of the emissions reductio n requirement of RSA 125-O:13, II, on an annual basis, following the compliance date of July 1, 2013.

b. The ratios of over-compliance credits to excess pou nds of mercury reduced shall be as follows:

i. 0.5 credits per pound reduced for reductions betwee n 80 and 85 percent; ii. 1 credit per pound reduced for reductions between 8 5 and 90 percent reduction; and iii. 1.5 credits per pound reduced for reductions of 90 percent or greater.

c. Over-compliance credits may be banked for future us e. The requirements of RSA 125-O:13, V shall not alter the emissions levels at which over-compliance credits are earned.
d. Should a federal rule applicable to mercury emissio ns at one or more of the affected sources be enacted, then over-compl iance credits may only be earned for emissions reductions that exceed the level required by the federal rule of the affected sources in aggr egate or the requirement of RSA 125-O:13, II, whichever is lower , at the same ratios listed in subparagraph (b) above.

e. At the request of the Owner, over-compliance credit s may be surrendered by the owner to the department and SO2 allowances shall be transferred to the owner at a rate of 55 tons SO 2 allowances for every one over-compliance credit. Transfer shall be limited to a maximum of 20,000 total tons SO2 allowances transfe rred in a given year, defined as the sum of all SO2 allowances rece ived by the affected sources under RSA 125-O:4, IV(a)(2) and IV (a)(3), and under this subparagraph. SO2 allowances shall be cr edited to the affected sources' accounts in the following year in accordance with RSA 125-O:4, IV(a)(4).

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Table 4 – Operational and Emission Limitations Item No. Regulatory Cite Applicable Emission Unit Applicable Requirement

22. Env-A 604.02 MKLC1 The limestone processing rate of the wet limestone ball mills shall not exceed 25 tons per hour 7

.



### B. Initial Compliance Demonstration Requirements The Owner shall demonstrate initial compliance with the emission limitations specified in Table 4 for the parameters contained in Table 5 below, wi thin 60 days after achieving stable FGD operation with both MK1 and MK2 exhausting through stack STMK3. The Owner shall perform the initial compliance demonstration requirements l isted in Table 5 below. In addition, the Owner shall perform all monitoring and testing requ irements in Table 6 to ensure compliance with emissions and operating limitations contained in Table 4.

Table 5: Initial Compliance Demonstration Requireme nts

Item No. Applicable

Emission Unit Parameter Method of Compliance Frequency of Method Regulatory

Basis

1. MK1 & MK2 with MK2- PC7 Performance

tests for
mercury a. The Owner shall conduct initial

performance tests for mercury to demonstrate compliance with the respective mercury emissions limitation in Table 4, Item 13. b. Testing shall be conducted and the results reported in accordance with 40 CFR 60, Sections 60.8(a), (b), (d), (e), and (f), and Appendix A. The following test methods or DES approved alternatives shall be used for the pollutants specified: i. Method 1 or 2 to determine exit velocity of stack gases; ii. Method 3 or 3A to determine carbon dioxide, oxygen, excess air, and molecular weight (dry basis) of stack
gases; iii. Method 4 to determine moisture content (volume fraction of water vapor) of stack gases; Within 60 days after achieving stable FGD operation with both MK1 and MK2 exhausting through stack STMK3 Env-A 802 &

40 CFR 60.8 (a), (b), (d)- (f)

7 The limestone processing equipment subject to this requirement consists of two wet limestone ball mil ls. Only one wet limestone ball mill is operated at a time. The second wet limesto ne ball mill will serve as a backup unit.

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Table 5: Initial Compliance Demonstration Requireme nts

Item No. Applicable

Emission Unit Parameter Method of Compliance Frequency of Method Regulatory

Basis

iv. For mercury, in accordance with the mercury monitoring requirement of RSA 125-O:15 and Table 6, Item 3 of this permit. 2. MK1 & MK2 Performance

Test for SO 2 a. The Owner shall conduct an initial

performance test for SO 2 to demonstrate compliance with the respective SO 2 emissions limitation in Table 4, Items 6 and 8. b. Testing shall be conducted and the results reported in accordance with 40 CFR 60, Sections 60.8(a), (b), (d), (e), and (f), and Appendix A. The following test methods or DES approved alternatives shall be used for the pollutants specified: i. Use of certified CEMS monitors. With the use of CEMS monitors, compliance will be determined based on a monthly average of CEMS data. Within 60 days after achieving stable FGD operation with both MK1 and MK2 exhausting through stack STMK3 Env-A 802 &

40 CFR 60.8 (a), (b), (d)- (f)

3. MK1 & MK2 General Stack Testing Requirements Compliance testing shall be planned and carried

out in accordance with the following schedule:

a. At the request of DES, submit to DES a pretest protocol at least 30 days prior to the commencement of testing which includes the following information: i. Calibration methods and sample data sheets; ii. Descriptions of the test methods to be used; iii. Pre-test preparation procedures; iv. Sample collection and analysis procedures;

v. Process data to be collected; and vi. Complete test program description. b. At the request of DES, participate in a pretest conference with a DES representative at least 15 days prior to the test date.

c. Emission testing shall be carried out under the observation of a DES representative. d. Within 60 days after completion of testing or within 15 days of receipt of test report, submit a copy of the test report to DES. Initial performance test and subsequent testing Env-A

802.03, 802.04, 802.05, & 802.11

4. MK1 & MK2 General Stack Testing Requirements Operating Conditions During a Stack

Emissions Test A compliance test shall be conducted under one Initial performance test and Env-A

802.10

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Table 5: Initial Compliance Demonstration Requireme nts

Item No. Applicable

Emission Unit Parameter Method of Compliance Frequency of Method Regulatory

Basis

of the following operating conditions:

a. Between 90 and 100 % of maximum operating capacity; b. A production rate at which maximum emissions occur; or

c. At such operating conditions agreed upon during a pre-test meeting conducted pursuant to Env-A 802.05. subsequent

tests



### C. Monitoring/Testing Requirements

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

Table 6 – Monitoring/Testing Requirements Item No. Device Parameter Method of Compliance Frequency of Method Regulatory

Cite 1. MK1 & MK2 Continuous

Emissions Monitoring Systems Site-Specific Monitoring Plan - Continuous

Emissions Monitoring Systems

a. The Owner shall submit a CEMS monitoring plan describing the proposed systems. The monitoring plan shall contain the information required under Env-A 808.04(c) and address all applicable monitoring requirements of Env-A 808, 40 CFR Part 60, and 40 CFR Part 75.

b. The CEMS monitoring plan in item a above, shall at a minimum, address the following operating scenarios:

i. CEMS monitoring for units MK1 and MK2 when both units MK1 and MK2 are operating and emissions are discharged through the common exhaust stack STMK3;

ii. CEMS monitoring for compliance with the SO 2 limitation specified in Table 4, Item 6 and 8;

iii. Monitoring for unit MK1 when emissions are discharged through stack STMK2 (bypass stack). At least 90 days prior to the installation of the CEM system Env-A

808.04(a)

2. MK1 & MK2 Continuous

Emissions Monitoring Systems Quality Assurance/Quality Control Plan

Requirements The Owner of a source required by this part to install, operate, and maintain an opacity or gaseou s As specified within regulation Env-A 808.06

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Table 6 – Monitoring/Testing Requirements Item No. Device Parameter Method of Compliance Frequency of Method Regulatory

Cite CEMS shall:

a. Prepare a quality assurance/quality control (QA/QC) plan, which shall contain written procedures for implementation of its QA/QC program for each CEMS;
b. File the QA/QC plan with DES no later than the time specified in Env-A 808.05(e) after the initial startup of each CEMS;

c. Review the QA/QC plan and all data generated by its implementation at least once each year;
d. Revise or update the QA/QC plan, as necessary, based on the results of the annual review, by:
ii. Documenting any changes made to the CEMS or changes to any information provided in the monitoring plan;
iii. Including a schedule of, and describing, all maintenance activities that are required by the CEMS manufacturer or that might have an effect on the operation of the system;
iiii. Describing how the audits and testing required by this part will be performed; and
iiv. Including examples of the reports that will be used to document the audits and tests required by this part;

e. Make the revised QA/QC plan available for review by DES at any time; and
f. Within 30 days of completion of the annual QA/QC plan review, certify in writing that the Owner will continue to implement the source’s existing QA/QC plan or submit in writing any changes to the plan and the reasons for each change;

g. Revision of the QA/QC plan is required if the results of emission report reviews, inspections, audits, review of the QA/QC plan, or any other information available to DES show that the plan does not meet the criteria specified in 40 CFR 60, Appendix F, Procedure 1, section 3; and
h. The QA/QC plan shall be considered an update to the CEMS monitoring plan

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Table 6 – Monitoring/Testing Requirements Item No. Device Parameter Method of Compliance Frequency of Method Regulatory

Cite required by Env-A 808.04. 3. MK1 & MK2 Mercury

Emissions Monitoring of Mercury Emissions

a. Prior to the availability and operation of CEMS, and subsequent to the baseline emissions testing under RSA 125-O:14, II, stack tests or another methodology approved by DES shall be conducted twice per year to determine mercury emissions levels from the affected sources.

b. Any stack tests performed shall employ a federally recognized and approved methodology, proposed by the Owner and employing a test protocol approved by DES.

c. When a federal performance specification takes effect and a mercury CEMS capable of meeting the federal specifications becomes available, a mercury CEMS, approved by DES, shall be installed on STMK3 as deemed appropriate by DES. Twice per year or until a mercury CEMS is in operation and approved by DES RSA 125-O:15

4. MK1 & MK2 Stack flow,

NO x , SO 2 , and CO 2 (or O 2 ), opacity The new stack (STMK3 from the FGD) serving

units MK1 and MK2 shall be equipped with flow monitoring, NO x , SO 2 , and CO 2 or O 2 CEMS and a continuous opacity monitor (COMS) 8 . The CEMS and COMS shall meet 40 CFR 75 requirements. Continuously Env-A 808.02(a) (new) and 40 CFR 75 §75.10(a)(2), §75.12, and Env-A 1211.03(f) 5. MK2-PC7 FGD

Operating Parameters a. The Owner shall continuously monitor the

scrubber liquor pH and FGD absorber exit gas temperature. b. The Owner shall calibrate or validate the accurate operation of the instruments measuring the parameters a minimum of once annually in accordance with manufacturer’s recommended procedures or alternative procedures as approved by DES. All records of the calibrations or validations shall be kept and made available upon request. Continuously RSA 125-C:6, XI

6. MK2-PC7 FGD Data

Acquisition System The Owner shall have a data acquisition system

for the FGD absorber exit gas temperature and scrubber liquor pH monitors, which calculates and monitors hourly averages and daily averages. Continuously RSA 125-C:6, XI

8 Due to excessive moisture in the flue gas exit ing the FGD system, the COMS will be installed prio r to the stack.

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Table 6 – Monitoring/Testing Requirements Item No. Device Parameter Method of Compliance Frequency of Method Regulatory

Cite 7. MK1 & MK2 Sulfur Test

Method for Coal The owner or operator shall use Method ASTM

D 4239-00 to determine the sulfur content of coal in pounds of sulfur per million BTU gross heat content. Each shipment of coal Env-A 806.04



### D. Recordkeeping Requirements The Owner is subject to the Recordkeeping requireme nts as contained in Table 7 below:

Table 7 – Applicable Recordkeeping Requirements Item No. Recordkeeping Requirement Frequency of Recordkeeping Applicable

Emission Unit Regulatory Cite

1. Record Retention and Availability

The Owner shall keep the required records on file. These records shall be available for review by DES upon request. Retain for a minimum of 5 years Emissions Units specified in Table 1 and Pollution Control Equipment specified in Table 3 Env-A 902

2. General Recordkeeping Requirements for

Process Operations The Owner shall keep monthly records of:

a. The quantity of limestone used as documented by limestone delivery records; and b. The hours of operation of the wet limestone ball mills. Monthly MKLC1 MK2-PC7 Env-A 903.02

3. The Owner shall maintain the standard

operating and maintenance procedures for the air pollution control equipment in a convenient location (e.g., control room/technical library) and make them readily available to DES upon request. Maintain at facility at all times MK2-PC7 Env-A 906.01

4. CEMS and Other Approved Monitoring

Methods Recordkeeping Requirements

a. The Owner shall record and maintain the information pursuant to 40 CFR Part 75, which includes the certification, quality assurance, and quality control records. b. The Owner shall record and maintain CEMS records according to the most stringent requirements of Env-A 808 and 40 CFR Part 75. As specified by regulation MK1, MK2,

MK2-PC7 Env-A 903.04

Env-A 808 40 CFR Part 75

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Table 7 – Applicable Recordkeeping Requirements Item No. Recordkeeping Requirement Frequency of Recordkeeping Applicable

Emission Unit Regulatory Cite

5. The Owner shall record the hours of operation

of MK1 and MK2 as follows:

a. Total hours of MK1 and MK2 each; and b. Total hours of MK1 when discharging through STMK2 (bypass stack) Monthly MK1 and MK2 Env-A 906

6. The owner or operator shall maintain the

following sulfur analysis records:

a. Records showing the maximum weight percentage sulfur and quantity of each fuel delivery shipment received; and b. Records showing either: 1. The analytical method used and the specified fuel analysis results of the shipment or consignment from which the shipment came; or 2. Delivery records sufficient to allow for traceability of the analytical results corresponding to each shipment received by the stationary source, showing: i. The date of delivery; ii. The quantity of delivery; iii. The type of fuel; iv. The maximum weight percentage sulfur; and

v. The name, address, and telephone number of the company making the delivery. Each shipment of coal MK1 & MK2 Env-A 806.05

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E. Reporting Requirements The Owner is subject to the reporting requirements identified in Table 8 below:

Table 8 – Applicable Reporting Requirements Item No. Reporting Requirement Frequency of Reporting Applicable

Emission Unit Regulatory Cite

1. Performance Test Reports

The Owner shall submit a report to DES documenting the results of the compliance stack emission test. The compliance stack emission test report shall contain the following information:

a. All the information required for the pre-test protocol as described in Env-A 802.04; b. All test data;

c. All calibration data; d. Process data agreed by DES and the Owner to be collected;

e. All test results; f. A description of any discrepancies or problems that occurred during testing or sample analysis;
g. An explanation of how discrepancies or problems were treated and their effect on the final results; and h. A list and description of all equations used in the test report, including sample calculations for each equation used. No later than 60 days after a performance test MK1, MK2 &

MK2-PC7 Env-A 802.11

2. Quarterly Reports

The Owner shall submit to DES no later than 30 calendar days after the end of the calendar quarter, the information required in Table 7, Item 4. Quarterly – 30 calendar days after the end of the calendar quarter MK1, MK2,

MK2-PC7 40 CFR 75,

Env-A 808.11

3. Semi-annual Report

The Owner shall submit to DES the following information on a semi-annual basis:

a. Hours of operation of MK1 and MK2 as required in Table 7, Item 5; and b. Limestone records as required in Table 7, Item 2. Semi-annual MK1, MK2, MKLC1 Env-A 910

4. Annual Emissions Compliance Report for

Mercury The Owner shall submit to DES a report of annual mercury emissions from the affected sources to demonstrate compliance with Item 13 of Table 4. This report shall include all references and methodologies used to calculate the total mercury emissions from the affected sources. Annually by April 15 th of each calendar year Affected

Sources as defined in RSA 125-O:12 Env-A 910

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Table 8 – Applicable Reporting Requirements Item No. Reporting Requirement Frequency of Reporting Applicable

Emission Unit Regulatory Cite

5. Quarterly Coal Report

The Owner shall submit to DES no later than 30 calendar days after the end of the calendar quarter, the information required in Table 7, Item 6. Submittal of the “Monthly Report of Cost and Quality of Fuel for Electric Plants,” will satisfy the requirements of this condition. Quarterly – 30 calendar days after the end of the calendar quarter MK1 & MK2 Env-A 910.01



### VII. Administrative Permit Amendments

A. Pursuant to Env-A 612.01, the Owner may implement t he 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 f inal action on a request for an administrative permit amendment in accordance with the provisions of Env-A 612.01(b) and (c).

VIII. Minor Permit Amendments

A. Pursuant to Env-A 612.03, the owner or operator of a source or device shall submit to the department a request for a minor permit amendment f or any proposed change to an existing permit condition which will not result in an increa se in the amount of a specific air pollutant currently emitted by the source or device and will not result in the emission of any regulated air pollutant or regulated toxic air pollutant currentl y not emitted by the source or device.

B. The request for a minor permit amendment shall: 1. Be in the form of a letter to the department; 2. Describe the proposed change; and 3. Describe any new applicable requirements that will apply if the change occurs.

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

D. The owner or operator may implement the proposed ch ange immediately upon filing a request for minor permit amendment with the department.

IX. Significant Permit Amendments

A. Pursuant to Env-A 612.04, the owner or operator sha ll submit an application to the department for a significant permit amendment for any proposed change to the physical structure or operation of the source or device covered by the te mporary permit which increases the amount of a specific air pollutant currently emitted by such source or device or which results in the emission of any regulated air pollutant currently not emitte d by such source or device.

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B. A request for a significant permit amendment shall include the following:

1. A complete application form, as described in Env-A 1703 through Env-A 1708, as applicable and provided by the department, containing all pert inent information with regard to the amendment including, if applicable, the information specified in Env-A 1709.

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

3. A description of:

a. The proposed change; b. The emissions resulting from the change; and

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

4. Where air pollution dispersion modeling is required for a source or device pursuant to Env-A 606.02, the information required pursuant to Env-A 606.03.

C. The department shall take take final action on a re quest for a significant permit amendment within 90 days of receipt of such a request, provid ed that the public notice and hearing procedures specified in Env-A 621 have been satisfi ed.

D. The owner or operator shall not implement the propo sed change until the department issued the amended permit.

X. Emission-Based Fee Requirements

A. The Owner shall pay an emission-based fee quarterly for this facility as calculated each calendar year pursuant to Env-A 705.03.

B. The Owner shall determine the total actual annual e missions from the facility to be included in the emission-based multiplier specified in Env-A 70 5.03(a) for each calendar year in accordance with the methods specified in Env-A 616.

C. The Owner shall calculate the annual emission-based fee for each calendar year in accordance with the procedures specified in Env-A 705.03 and t he following equation:

Where:

FEE = The annual emission-based fee for each calen dar year as specified in Env-A 705. E = The emission-based multiplier is based on the calculation of total annual

emissions as specified in Env-A 705.02 and the prov isions 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 calcu lated in Env-A 705.03(c). ISF = The Inventory Stabilization Factor as speci fied in Env-A 705.03(d). ISF * CPIm * DPT * E = FEE

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D. The Owner shall contact the DES each calendar year for the value of the Inventory Stabilization Factor.

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

F. The Owner shall submit, to the DES, payment of the emission-based fee and a summary of the calculations referenced in Sections X.B. and C. of this Permit for each calendar year. The total emission-based fee shall be paid in four equal inst allments on a quarterly basis. The quarterly payments shall be made in accordance with Env-A 705 .04 on the 15 th 

### day of the following months:

1. July of the year to which the fee applies (e.g., Ja nuary, February, March 2007 emission fees are due July 15, 2007);

2. October of the year to which the fee applies (e.g., April, May, June 2007 emission fees are due on October 15, 2007).

3. January of the following year (e.g., July, August, September 2007 emission fees are due on January 15, 2008);

4. April of the following year (e.g., October, Novembe r, December 2007 emission fees are due on April 15, 2008).

The Owner shall pay any remaining balance of the to tal annual emission-based fee no later than April 15 th 

### of the following year.

The emission-based fee and summary of the calculati ons shall be submitted to the following address:

New Hampshire Department of Environmental Services Air Resources Division 29 Hazen Drive P.O. Box 95 Concord, NH 03302-0095 ATTN.: Emissions Inventory

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

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XI. Permit Deviation

In accordance with 40 CFR 70.6(a)(3)(iii)(B), the O wner 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. Th is 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 preventat ive measures taken.

Within 10 days of discovery of the permit deviation , the Owner shall submit a written report including the above information as well as the foll owing: preventive measures taken to prevent future occurrences; date and time the permitted dev ice returned to normal operation; specific device, process or air pollution control equipment that con tributed to the permit deviation; type and quantity of excess emissions emitted to the atmosphere due t o permit deviation; and an explanation of the calculation or estimation used to quantify excess e missions.

Said Permit deviation shall also be submitted in wr iting to the DES in the semi-annual summary report of monitoring and testing requirements due J uly 31st and January 31st of each calendar year. Deviations are instances where any Permit condition is violated and has not already been reported as an emergency pursuant to 40 CFR 70.6(g).

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