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The State of New Hampshire DEPARTMENT OF ENVIRONMENTAL SERVICES

____________

Thomas S. Burack, Commissioner

DES Web site: www.des.nh.gov P.O. Box 95, 29 Hazen Drive, Concord, New Hampshire 03302-0095

Telephone: (603) 271-1270 • Fax: (603) 271-1381 • TDD Access: Relay NH 1-800-735-2964

September 13, 2013 Jim Dombrosk, Director, Energy and Utilities University of New Hampshire 6 Leavitt LN Durham, NH 03824 RE: On-Site Full Compliance Evaluation Report Dear Mr. Dombrosk:

The New Hampshire Department of Environmental Services, Air Resources Division (“DES”) has completed a Full Compliance Evaluation of the University of New Hampshire (“UNH”). The compliance evaluation included an on-site inspection completed on July 31, 2013 and August 1, 2013. This is a copy of the On-Site Full Compliance Evaluation Report for your review and records.

DES identified deficiencies during this compliance evaluation, as detailed in this report. The results of the compliance evaluation have been forwarded to the Enforcement Section for

further review. If you have any questions, please do not hesitate to give Alan Moulton a call at (603) 271-6797 or by email at [email protected]. Sincerely,

Greg Helve Compliance Assessment Section Supervisor Air Resources Division cc: Town Administrator, Town of Durham, 15 Newmarket Road, Durham, NH 03824 City Manager, City of Rochester, 31 Wakefield Street, Rochester, NH 03867 Tim Donnelly, POWER Engineers, Inc.,303 U.S. Route One, Freeport, ME 04032

University of New Hampshire Inspection Date: July 31, 2013 On-Site Full Compliance Evaluation Report Date: September 13, 2013

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Abbreviations and Acronyms AAL Ambient Air Limit acf actual cubic foot ags above ground surface ASTM American Society of Testing and Materials Btu British thermal units CAS Chemical Abstracts Service CEMS Continuous Emission Monitoring System cfm cubic feet per minute CFR Code of Federal Regulations CO Carbon Monoxide DER Discrete Emission Reduction DES New Hampshire Department of Environmental Services Env-A New Hampshire Code of Administrative Rules – Air Resources Division ERC Emission Reduction Credit ft foot or feet ft3 cubic feet gal gallon HAP Hazardous Air Pollutant hp horsepower hr hour kW kilowatt lb pound LFGTE Landfill Gas to Energy LPG Liquefied Petroleum Gas MM million MSDS Material Safety Data Sheet MW megawatt NAAQS National Ambient Air Quality Standard NG Natural Gas NOx Oxides of Nitrogen NSPS New Source Performance Standard PM10 Particulate Matter < 10 microns ppm parts per million psi pounds per square inch RACT Reasonably Available Control Technology RSA Revised Statues Annotated RTAP Regulated Toxic Air Pollutant scf standard cubic foot SO2 Sulfur Dioxide TSP Total Suspended Particulate tpy tons per consecutive 12-month period USEPA United States Environmental Protection Agency VOC Volatile Organic Compound


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I. Facility Description DES conducted an On-Site Full Compliance Evaluation of UNH on July 31, 2013 and August 1, 2013. The compliance evaluation covers the period 2010 to July 31, 2013 , and the result is presented herein. UNH, Durham Campus, is an institution of higher education, is part of the University System of New Hampshire, and is operated by the State of New Hampshire. The university was founded in 1866 as a State-operated Agricultural and Mechanical College. The predominant sources of air pollutant emissions at UNH are their central heating and cogeneration plant, a boiler located at the New England Center, and emergency generators located throughout the university campus. UNH recently constructed a Landfill Gas to Energy facility on two properties. At the existing cogeneration plant on the Durham campus, UNH added a supplemental turbine (EU19) that is capable of operating on processed landfill gas. An existing combustion turbine (EU07) also is capable of burning processed landfill gas in addition to natural gas and distillate (#2) fuel oil. UNH also constructed a landfill gas processing facility at the Turnkey Landfill in Rochester, NH. The landfill gas processing facility will remove contaminants from the raw landfill gas and compress the landfill gas for transport (via pipeline) to the Durham cogeneration plant. For purposes of air permitting, the two facilities (UNH Durham campus and UNH landfill gas to energy facility in Rochester) are considered to be a single source since the landfill gas processing facility is considered as a support facility to the Durham campus.

Facility name and address University of New Hampshire 6 Leavitt Lane Durham, New Hampshire 03824

County Strafford Telephone (603) 862-2650 AFS# 3301700009

Source Type Title V (Mega Site)

Inspection Date/Time July 31, 2013; 10:00 am (Durham) August 1, 2013; 10:00 am (Rochester)

Inspection Type On-Site Full Compliance Evaluation

Weather 70-75 Deg. F., calm wind, sunny (July 31) 75 Deg. F., calm wind, sunny (August 1)

Inspection Period 2010 to July 31, 2013 Inspected by Alan Moulton, DES Compliance Assessment Engineer

Catherine Beahm, DES Technical Assistance Specialist (Durham only) Ben Rollins, DES Intern

Source Contact(s) David Bowley, Utility Systems Manager

Last Inspection September 30, 2010, Durham campus October 7, 2010, Rochester facility


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Last Inspection Results:

a) UNH recently provided an updated list of “Non EU10” emergency generators dated January 2011. It should be noted that the new list contains 21 additional emergency generators from the original list in the Permit and several changes to the original list. On that list, there are 8 diesel generators that are above the permitting threshold of 1.5 MMBtu/hr and which, therefore, are not considered to be insignificant. UNH filed a permit application for these devices and for any changes to the original “insignificant” list in the original Permit,

b) UNH has not reported the yearly run hours of each emergency generator. DES recommends that UNH report the yearly run hours of each emergency generator to demonstrate compliance with Table 4a, Item 5 of the Permit,

c) UNH did not report the LFG usage in the Siemens turbine (EU7) and the duct burner (EU8) as required by Table 9, item 4 and Table 10, Item 1 of the Permit. UNH had been combining the use of natural gas and LFG and reporting the total usage as natural gas only. UNH is now reporting the use of natural gas and landfill gas separately. It should be noted that while the emission factors may be the same for both fuels, the heating values of the two fuels are different which may have an impact on the amount of emissions,

d) UNH provided the origin of several of the emission factors in the Annual Emission Statement as required by Table 7, Item 12a of the Permit. “Emission factors based on current permit limits” is not an acceptable origin. Some examples of acceptable origins include: AP-42, latest stack test results, CEM data, vendor data and emission data from similar devices,

e) UNH used several incorrect emission factors in the 2009 Annual Emission Report. These issues were discussed over the telephone and by email between DES Emission Inventory Group and the consultant. UNH was invoiced for fees based on using the corrected emission factors. UNH submitted an amended 2009 Annual Emission Statement using the corrected emission factors, making the corrections noted above and submitted it to DES by March 18, 2011, and

f) UNH did update and submit its air toxics compliance demonstration to DES by March 18, 2011.

Permit Number(s):

TV-OP-010: Issued April 11, 2007, Expired April 30, 2012, (Application Shield applies) Significant Permit Modification November 3, 2009, Administrative Amendment September 1, 2010 TP-B-0531: Issued July 25, 2007, Expired January 31, 2011, (Application Shield applies) Significant Permit Amendment November 7, 2008, January 31, 2011, Permit Reissuance January 22, 2010


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On October 26, 2011, UNH filed with DES a renewal application for the Title V Permit. DES has deemed the application complete. UNH has application shield and can operate under the current permits until a new Title V Permit is issued. The on-site inspection included an opening meeting to discuss the purpose of the inspection as well as the rules pertaining to claims of confidentiality and facility safety concerns. UNH agreed to the inspection and authorized access. Material provided and operations conducted by the facility at the time of the inspection was not claimed as confidential. This inspection was conducted over two days. The first day took place at the Durham campus. The second day was at the buildings UNH has on the Turnkey Landfill in Rochester, NH. For purposes of this full compliance evaluation, the terms and conditions of TV-OP-010 have been used for EU1 - EU11 and the terms and conditions of TP-B-0531 have been used for EU14 - EU19. In addition, TP-B-0531 contains additional terms and conditions that apply to EU7 and EU8 (listed in TP-B-0531 as EU07 and EU08) and this evaluation also determined compliance with those additional terms and conditions.

II. Emission Unit Identification and Facility Wide Emissions Table 1 below, using data from permits TV-OP-010 and TP-B-0531, lists the permitted emission units as verified during the inspection.

Table 1 – Emission Unit Identification, Significant Activities

Emission Unit ID Device or Process Identification

Manufacturer Model Number Serial Number

Installation Date Maximum Design Capacity and Fuel Types

EU1 Boiler #1 (Central Heating Plant)

Babcock & Wilcox FF2972 NA

1963 47.3 MMBtu/hr

No. 6 fuel oil, equivalent to 315.3 gal/hr; or Natural gas, equivalent to 46,373 scf/hr


Babcock & Wilcox FF2972 Number NA

1963 47.3 MMBtu/hr No. 6 fuel oil, equivalent to 315.3 gal/hr; or Natural gas, equivalent to 46,373 scf/hr


Babcock & Wilcox FF2713 NA



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Riley NA NA

1948

Decommissioned in 2010

47.3 MMBtu/hr No. 6 fuel oil, equivalent to 315.3 gal/hr; or Natural gas, equivalent to 46,373 scf/hr


Cleaver Brooks CB-600-400 NA

1986

Blew a tube in March 2012 and is permanently

disabled.

16.7 MMBtu/hr No. 6 fuel oil, equivalent to 111.7 gal/hr; or Natural gas, equivalent to 16,373 scf/hr

EU6 New England Center Boiler

Cleaver Brooks CB-662-300 NA


EU7 Siemens Alstom Power Combustion Turbine (CT)

Siemens Power Tempest SGT-300 Contract #: 1405032 NW0044

2004 1. Operation shall be limited to No. 2 fuel oil, natural gas, or processed landfill gas.

2. The maximum heat input shall be limited to: a. 104.8 MMBtu/hr while firing

No. 2 fuel oil at 0°F (equivalent to 748.6 gal/hr), and chiller OFF;

b. 106.0 MMBtu/hr while firing natural gas at 0°F (equivalent to 103,922 scf/hr) and chiller OFF;

c. 106.0 MMBtu/hr while firing processed landfill gas at 0°F (equivalent to 140,957scf/hr) and chiller OFF; and

d. Any combination thereof.

EU8 Heat Recovery Steam Generator With Duct Burner (Low NOx Burner)

Energy Recovery International VC-4 4759 Nat Com Burner DBG 582R 9511-1

2004 1. Operation shall be limited to natural gas and processed landfill gas.

2. The maximum heat input shall be limited to 66.3 MMBTU/hr (equivalent to 65,000 scf/hr).

EU9 Black Start Emergency Generator at the Combustion Turbine Building 750 KW

Caterpillar 3412/SR4B BLG02735

2004 7.5 MMBtu/hr Diesel fuel, equivalent to 54.8 gal/hr


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EU10 Emergency Generators (EG1 through EG7 listed in Attachment A) which are included in the facility wide emissions cap along with EU1 through EU9.

Prior to 1999 See Attachment A

EU11 See Attachment A for a list of all emergency Generators on the UNH campus above permitting thresholds of 1.5 MMBtu/hr gross heat input rate combined for liquid fuels and 10.0 MMBtu/hr gross heat input rate combined for gaseous fuels, and which individually are above 150,000 Btu/hr gross heat input rate.

See Attachment A See Attachment A

EU14 Reciprocating Engine #1 Caterpillar G3520C GZJ00311

2009 1. Operation shall be limited to the combustion of treated or processed landfill gas.


EU15 Reciprocating Engine #2 Caterpillar G3520C GZJ00310

2009 1. Operation shall be limited to the combustion of treated or processed landfill gas.


EU16 Supplemental Utility Flare

(Nonassisted)

Perennial Energy FL-16-C FL2-1575

2008 1. Operation shall be limited to the combustion of untreated (raw) or treated or processed landfill gas.


EU17 Standby Utility Flare

(Nonassisted)

Perennial Energy FL-16-C FL3-1575

2008 1. Operation shall be limited to the combustion of untreated (raw) or treated or processed landfill gas.


EU18 Thermal Oxidizer Perennial Energy CP-1 CP-1575

2009 1. Operation shall be limited to the combustion of treated landfill gas and waste gas produced from the regeneration of treatment media.

2. The maximum heat input to this device shall be limited to 36 MMBTU/hr.


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EU19 Solar Mercury 50 Recuperative Turbine

Solar Model # Mercury 50-6000R Engine Serial # 0048R Package Serial # PG08926

2009 1. Operation shall be limited to the combustion of processed landfill gas.


There are no devices assigned to EU12 and EU13. On July 31, 2013, DES observed Boilers #1 through #5 (EU1 through EU5), the Siemens and the Solar Combustion Turbines (EU7 and EU19), the Heat Recovery Steam Generator (EU8), and the Black Start Emergency Generator (EU9), which are identified in Table 1 and the facility has not added devices classified as significant or insignificant activities. UNH has received a waiver to test the use of processed landfill gas in the boilers in the Central Heating Plant.

On August 1, 2013, DES observed the devices located at the Rochester facility, Reciprocating Engines #1 and #2 (EU14 and EU15), the Supplemental Utility Flare (EU16), the Standby Utility Flare (EU17), and the Thermal Oxidizer (EU18), which are identified in Table 1 and the facility has made no changes to these devices nor has it added devices classified as significant or insignificant activities. Insignificant Activities UNH has identified insignificant activities within Permit TV-OP-010. UNH has filed a renewal application for the Title V Permit. This application includes changes to the list of insignificant activities. Permitting is reviewing and updating the list of insignificant activities for the new permit. See Appendix A (for emergency generators) and Appendix B (for boilers and furnaces) for a preliminary list of insignificant activities. When the list of insignificant activities is finalized, the list will be included in the Engineering Summary. Emissions from the insignificant activities for 2010, 2011, and 2012 were included in the annual emission reports.


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The tables below lists the facility-wide reported annual emissions for the review period.

Reported Annual Emissions for EU01 through EU10, including Insignificant Activities

Nitrogen Oxides (tpy)

Sulfur Dioxide

(tpy)

Carbon Monoxide

(tpy)

Particulate Matter (tpy)

VOCs (tpy)

Permitted Limits 77.83 257.20 106.34 30.81 25.74

2012 27.21 5.88 48.13 11.88 12.33 2011 29.15 7.40 51.36 13.35 13.58 2010 27.01 9.44 19.84 4.71 4.48

Reported Annual Emissions for EU14 through EU19

Nitrogen Oxides (tpy)

Sulfur Dioxide

(tpy)

Carbon Monoxide

(tpy)

Particulate Matter (tpy)

VOCs (tpy)

Permitted Limits 41.52 39.00 182.00 23.14 48.24

2012 8.74 4.76 79.15 5.73 6.12 2011 10.09 5.93 60.15 5.72 6.34 2010 12.71 9.70 71.49 9.52 5.71

III. Control Equipment Table 2, using data from permit TP-B-0531, lists the required control equipment for the facility's devices, as verified during the inspection.

Table 2 – Pollution Control Equipment Identification Pollution Control

Equipment ID Description of Equipment Purpose Emission Unit

Controlled PCE01 Thermal Oxidizer (EU18) Waste gases generated from LFG

treatment system (siloxanes, VOCs) Main Gas Processing Unit

PCE02 SulfaTreat System Sulfur removal from LFG through reaction with iron to form iron sulfide

Main Gas Processing Unit

PCE03 Molecular Sieve associate with the Pressure Swing Adsorption (PSA) unit

Carbon dioxide removal via molecular sieve

Main Gas Processing Unit

PCE04 Supplemental Utility Flare (EU16)

Non-methane Organic Compounds (NMOCs)

Untreated Landfill Gas from TREE and Treated and Processed Gas from UNH Processes


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Table 2 – Pollution Control Equipment Identification Pollution Control

Equipment ID Description of Equipment Purpose Emission Unit

Controlled PCE05 Standby Utility Flare (EU17) Non-methane Organic Compounds

(NMOCs) Untreated Landfill Gas from TREE and Treated and Processed Gas from UNH Processes

PCE06 Preliminary Treatment Unit Particulate matter Untreated Landfill Gas from TREE

IV. Stack Criteria Table 3 below, using data from permits TV-OP-010 and TP-B-0531, lists the permitted stack requirements for the facility. During the inspection, DES observed the stacks listed, except for Stack #3, and noted that the stacks were vertical, and there have been no modifications except for Stack #1, in which the height was reduced from 205 feet to 160 feet above ground level, in 2012. This stack reduction was reviewed by DES, showed compliance with the NAAQS, and was approved on April 20, 2012.

Table 3 – Stack Criteria

Stack Number Emission Unit or Pollution Control

Equipment ID

Minimum Height (feet above ground

level)

Maximum Exit Diameter

(feet)

Stack #1 EU1, EU2, EU3, and EU4 (Combined Stack)

205

160 (2012)

8.5

Stack #2 EU5 50 3.0

Stack #3 EU6 35 2.0

Stack #4 EU7/EU8 100 5.0

Stack #14 EU14 32 1.3

Stack #15 EU15 32 1.3

Stack #16 EU16 30 5.0

Stack #17 EU17 30 5.0

Stack #18 EU18 49 9.0

Stack #19 EU19 100 4.1


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V. Compliance with Operating and Emission Limitations Table 4b below, taken from permit TV-OP-010, lists the Federally Enforceable emission limitations for the facility, and any deficiencies noted during the evaluation.

Table 4b – Federally Enforceable Emissions Limitations Device NOx SO2 PM10 CO VOC H2SO4 Mist

EU5 8.24 tpy 35.29 tpy 2.19 tpy PM10 & 2.55 tpy TSP

0.75 tpy No limit No limit

EU7 (gas) 25 ppmvd at 15% O2 or 0.092 lb/MMBtu

0.0043 lb/MMBtu

2.12 lb/hr or 0.0319 lb/MMBtu

0.1122 lb/MMBtu

0.0321 lb/MMBtu

0.0003 lb/MMBtu

EU7 (oil) 65 ppmvd at 15% O2 or 0.253 lb/MMBtu

0.3903 lb/MMBtu

5.25 lb/hr or 0.0804 lb/MMBtu

0.1150 lb/MMBtu

0.033 lb/MMBtu

0.030 lb/MMBtu

EU7 (gas) & EU8 (gas)

0.1019 lb/MMBtu or 17.55 lb/hr






EU7 (oil) & EU8 (gas)







EU9 7.17 gram/bHP-hr or 15.9 lb/hr





No limit

Facility Wide Caps

77.83 tpy 257.20 tpy 30.81 tpy 106.34 tpy 25.74 tpy 6.90 tpy

For the Siemens Turbine (EU7) compliance is determined through stack testing and a NOx CEMS. On February 21-23, 2007, stack testing was conducted for emissions of NOx, SO2, PM10, and CO. The results were that the emissions of these gases were in compliance with the limits in Permit TV-OP-010. The NOx CEMS has shown that there have been some compliance issues, see Permit Deviation Section of this report. For the Heat Recovery Steam Generator (EU8) compliance is determined through stack testing. On February 21-23, 2007, stack testing was conducted for emissions of NOx, SO2, PM10, and CO. The results were that the emissions of these gases were in compliance with the limits in Permit TV-OP-010. The Boiler #5 (EU05) and the Black Start Emergency Generator (EU09) have not been tested. Boiler #5 has been permanently damaged beyond repair. EU09 is an emergency generator, which testing is not required.


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Table 5 below, taken from permit TP-B-0531, lists a summary of emission limitations for the facility, and any deficiencies noted during the evaluation.

Table 5 – Summary of Emission Limitations (Emissions limitations are based on a 3-hour averaging period unless otherwise specified)

Pollutant EU14 Reciprocating

Engine #1

EU15 Reciprocating

Engine #2


EU17 Standby

Utility Flare

EU18 Thermal Oxidizer

EU19 Supplemental

Turbine

Regulatory Citation

NOx limit 0.50 g/bhp-hr (BACT/LAER)

2.5 g/bhp-hr (NOx RACT limit – one-

hour average)

0.50 g/bhp-hr (BACT/LAER)

2.5 g/bhp-hr (NOx RACT limit – one-

hour average)

0.068 lb/MMBtu

(BACT/LAER)

0.068 lb/MMBtu

(BACT/LAER)

0.065 lb/MMBtu

(N/A) (24-hour averaging

period)

5 ppm @15% O2

(BACT/LAER) 25 ppm @15%

O2

(NOx RACT limit)

NOx limit for multiple

devices

41.52 tons per consecutive 12 month period for devices EU14 through EU19 combined.

NOx LAER Control

Technology

Lean Burn Design, Air/Fuel Ratio Controller, Intercooler Good Combustion Practices

Open Flare Design Good Combustion Practices

N/A Dry Low NOx Combustion Technology Good Combustion Practices

Env-A 618.03(a)

(LAER)

Env-A 619.03(a) 40 CFR 52.21

(BACT)

CO limit 2.75 g/bhp-hr (BACT)

2.75 g/bhp-hr

(BACT)

0.37 lb/MMBtu (BACT)


0.065 lb/MMBtu


period)

10 ppm @15% O2(BACT)

CO limit for multiple

devices


CO BACT Control

Technology

Good Combustion Practices Good Combustion Practices N/A Good Combustion

Practices

Env-A 619.03(a) 40 CFR 52.21

(BACT)

SO2 limit 0.046 g/bhp-hr 0.046 g/bhp-hr 0.149 lb/MMBtu

0.149 lb/MMBtu

0.015 lb/MMBtu (24-hour averaging

period)

0.002 lb/MMBtu

SO2 limit for multiple

devices


RSA 125-C:6, XI

TSP/PM10 limit

0.10 g/bhp-hr (BACT)

0.10 g/bhp-hr (BACT)



0.042 lb/MMBtu


period)


Env-A 619.03(a) 40 CFR 52.21

(BACT)


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Table 5 – Summary of Emission Limitations (Emissions limitations are based on a 3-hour averaging period unless otherwise specified)

Pollutant EU14 Reciprocating

Engine #1

EU15 Reciprocating

Engine #2


EU17 Standby

Utility Flare

EU18 Thermal Oxidizer

EU19 Supplemental

Turbine

Regulatory Citation

TSP/PM10 limit for multiple devices


TSP/PM10 BACT Control

Technology

Good Combustion Practices Good Combustion Practices N/A Good Combustion

Practices

VOC limit 0.70 g/bhp-hr 0.70 g/bhp-hr 0.060 lb/MMBtu

0.060 lb/MMBtu

0.065 lb/MMBtu (24-hour averaging

period)

0.013 lb/MMBtu

VOC limit for multiple

devices


RSA 125-C:6, XI

Compliance is determined through stack testing. On June 26, 2012, stack testing was conducted on the Thermal Oxidizer (EU18) for emissions of CO, SO2, TSP, VOC, and NOx. The test results for this device were in compliance with the limits in Permit TP-B-0531. Engines EU14 and EU15 were tested on June 27, 2012 for emissions of NOx and CO. CO emissions exceeded the limit of 2.75 gm/bhp-hr stated in Table 5 of permit TP-B-0531. On July 5, 2012, UNH shutdown EU14 and EU15. UNH did a cylinder head rebuild and retested on July 19, 2012. Test results indicated the CO emissions were below the permit limits. NOx test results for these devices were in compliance with the limits in Permit TP-B-0531. On March 25, 2013, stack testing was conducted on the Solar Turbine (EU19) for emissions of NOx, SO2, and CO. The test results for this device were in compliance with the limits in Permit TP-B-0531. In accordance with Table 7, Item 15 of permit TP-B-0531, NOx testing on the Solar Turbine (EU19) is due every two years or in November 2011. The required test in 2011 was not done and was subsequently conducted on March 23, 2012. The two flares (EU16 & EU17) have not been tested. Flares have not been required to be tested.


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Table 3 below, taken from permit TV-OP-010, lists the State-only operation and emission limitations for the facility, and any deficiencies noted during the evaluation.

Table 3 – State-only Enforceable Operational and Emission Limitations

Item # Applicable Requirement Applicable

Emission Unit Rule Citation Compliant

1. Required Emission Reductions From Class B Major Sources

Annual sulfur dioxide emissions from each Class B major source shall have an average calendar year emission rate not to exceed 1.6 pounds of sulfur dioxide per million Btu heat input, equivalent to No. 6 fuel oil with 1.5 percent sulfur by weight, which is 75 percent of the baseline average emission rate for Class B major sources.

Facility Wide Env-A 403.01

Yes

Table 6 below, taken from permit TP-B-0531, lists the State-only operation and emission limitations for the facility, and any deficiencies noted during the evaluation.




1. Facility-Wide HAP Emission Limitation Facility-wide emissions of Hazardous Air Pollutants (HAPs, as defined in Section 112 of the 1990 Clean Air Act Amendments) shall be limited to less than 10 tpy for any individual HAP and 25 tpy for all HAPs combined.

Facility Wide Env-A 604.02(a)(1)

Yes

2. 24-hour and Annual Ambient Air Limit The emissions of any Regulated Toxic Air Pollutant (RTAP) shall not cause an exceedance of its associated 24-hour or annual Ambient Air Limit (AAL) as set forth in Env-A 1450.01, Table Containing the List Naming All Regulated Toxic Air Pollutants.

Facility Wide Env-A 1400

Yes

Finding: A toxics compliance determination has been conducted for the processed landfill gas going to the boilers. The components meet the AALs. A review has not been conducted on the processed landfill gas going to the two turbines. A gas chromatograph of the landfill gas fed to the Siemens Turbine shows only 12 components that make up the processed landfill gas. All of these components (except for CO2, O2 and N2) are lower in the processed landfill gas compared to natural gas. This shows that the processed landfill gas is cleaner that natural gas and it isn't necessary at this time to conduct a toxics review on the processed landfill gas to the turbines. On April 26, 2013, UNH completed a toxics compliance determination that included the whole facility. The result of the determination indicated that the facility was in compliance with the latest changes in Env-A 1400. On July 10, 2013, a toxics compliance determination was done on the new water treatment chemicals. The results of the determination indicated that the chemicals were in compliance with the requirements in Env-A 1400.


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3. Revisions of the List of RTAPs In accordance with RSA 125-I:5 IV, if the Division revises the list of RTAPs or their respective AALs or classifications under RSA 125-I:4, II and III, and as a result of such revision the Owner or Operator is required to obtain or modify the permit under the provisions of RSA 125-I or RSA 125-C, the Owner or Operator shall have 90 days following publication of notice of such final revision in the New Hampshire Rulemaking Register to file a complete application for such permit or permit modification.

Facility Wide RSA 125-I:5 IV

No

Findings: UNH did not determine, within 90 days following the publication of notice of the revision to Env-A 1400, whether it needed to apply for a permit or modify its existing permit as a result of the latest revision to the AALs in Env-A 1400. A compliance demonstration pursuant to Env-A 1400 was performed on April 26, 2013, and from this demonstration, it was determined that UNH did not need to obtain or modify the permit.

4. Visible Emission Standard for Fuel Burning Devices Installed After May 13, 1970 The average opacity from fuel burning devices installed after May 13, 1970 shall not exceed 20 percent for any continuous 6-minute period.

EU7 EU8

EU14 EU15 EU16 EU17 EU18 EU19

Env-A 2002.02

Yes

5. Activities Exempt from Visible Emission Standards The average opacity shall be allowed to be in excess of those standards specified in Env-A 2002.02 for one period of 6 continuous minutes in any 60 minute period during startup, shutdown, or malfunction.

EU7 EU8


Env-A 2002.04(c)

Yes

6. Particulate Emission Standards for Fuel Burning Devices Installed on or After January 1, 1985 The particulate matter emissions from fuel burning devices installed on or after January 1, 1985 shall not exceed 0.30 lb/MMBtu.

EU7 EU8


Env-A 2002.08

Unknown

Finding: The Siemens Turbine (EU7) was tested for particulate on February 21, 2007 and is in compliance with the 0.30lb/MMBtu limit. For the remaining emission units listed, stack testing has not been conducted and is not required at this time.


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7. NOx RACT Emission Standard for Combustion TurbineOn and after November 1, 2002, all gas-fired turbines constructed after May 27, 1999, shall be limited to an hourly average NOx RACT emission limit of 25 ppmvd, corrected to 15% O2, or 0.092 lb. per million Btu, when operating on gas.

EU19 Env-A 1306.02 (effective 10-31-

2010) (formerly Env-A

1211.06(d))

Yes

8. NOx Emissions Standard for Stationary Combustion Turbines Subject to 40 CFR Part 60 Subpart KKKK NOx emissions from the Solar Mercury Recuperative Turbine shall be limited to 96 ppm at 15% O2 or 5.5 lb per MWh of useful energy

EU19 40 CFR § 60.4320

Yes

9. SO2 Emissions Standard for Stationary Combustion Turbines Subject to 40 CFR Part 60 Subpart KKKK a. SO2 emissions from the Solar Mercury

Recuperative Turbine shall be limited to 0.90 pounds per megawatt-hour (lb/MWh) gross output.

b. As an alternative to item (a) above, the owner or operator may comply with this part by burning fuel containing total potential sulfur emissions less than or equal to 0.060 lb SO2/MMBtu heat input.

EU19 40 CFR § 60.4330

Yes

10. The owner or operator must operate and maintain the stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction.

EU19 40 CFR § 60.4333(a)

Yes

11. Pollution Control Equipment Operation and Maintenance: a. The combustion chamber shall be maintained at a

minimum temperature of 1,280oF, based on an hourly average; and

b. The thermal oxidizer shall be maintained in accordance with manufacturer’s recommendations.

EU18 RSA 125-C:6, XI

Yes

12. Flares shall be designed for and operated with no visible emissions as determined by the methods specified in Table 7, Item 9, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours.

EU16 EU17

Env-A 604.01

Yes

13. Flares shall be operated with a flame present at all times when landfill gas is delivered to the flares as determined by the methods specified in Table 7, Item 19.

EU16 EU17

Env-A 604.01 Yes


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14.

The owner or operator shall adhere to one of the following two conditions: a. Nonassisted flares shall be used only with the net

heating value of the gas being combusted being 7.45 MJ/scm (200 Btu/scf) or greater and designed for and operated with an exit velocity less than 18.3 m/sec (60 ft/sec). The net heating value of the gas being combusted shall be determined by the methods specified in Table 7, Item 3.

b. Flares shall be used that have a diameter of 3 inches or greater, are nonassisted, have a hydrogen content of 8.0 percent (by volume), or greater, and are designed for and operated with an exit velocity less than 37.2 m/sec (122 ft/sec) and less than the velocity, Vmax, as determined by the following equation:

Vmax = (XH2-K1)*K2Where: Vmax = Maximum permitted velocity, m/sec K1 = Constant, 6.0 volume percent hydrogen K2 = Constant, 3.9 (m/sec)/volume-percent hydrogen XH2 = The volume-percent of hydrogen, on a wet basis, as calculated by using the methods listed in Table 7, Item 5

c. The actual exit velocity of a flare shall be determined by the methods specified in Table 7, Item 4.

EU16 EU17

Env-A 604.01

Yes

15. Operate the Preliminary Treatment Unit (PCE06) in accordance with the provisions of Table 7, Item 20.

PCE06 Env-A 604.01 Yes

16. Operate the Preliminary Treatment Unit (PCE06) at all times when the collected gas is routed to the system.

PCE06 Env-A 604.01 Yes

17. At all times, including periods of startup, shutdown, and malfunction (SSM), the owner or operator must operate and maintain the applicable emission units (EU16, EU17 and PCE06), in a manner consistent with safety and good air pollution control practices for minimizing emissions. During a period of SSM, this general duty to minimize emissions requires that the owner or operator reduce emissions of raw landfill gas to the greatest extent which is consistent with safety and good air pollution control practices.

EU16 EU17

PCE06

Env-A 604.01

Yes


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Table 4a below, taken from permit TV-OP-010, lists the Federal operation and emission limitations for the facility, and any deficiencies noted during the evaluation.

Table 4a– Federally Enforceable Operational and Emission Limitations Item

# Applicable Requirement Applicable Emission Unit Rule Citation Compliant

1. Maximum Sulfur Content Allowable in Liquid Fuels The sulfur content of No. 2 fuel oil shall not exceed 0.40 percent sulfur by weight.

Facility Wide Env-A 1604.01(a) & Temporary

Permit FP-T-0110

Yes

2. Maximum Sulfur Content Allowable in Gaseous Fuels The sulfur content of natural gas shall not exceed 15 grains of sulfur per 100 cubic feet of gas, calculated as hydrogen sulfide at standard temperature and pressure.

Facility Wide Env-A 1605.01(a) & Temporary

Permit FP-T-0110

Yes

3. The facility netted out of Non-attainment New Source Review (NSR) and Prevention of Significant Deterioration (PSD) program requirements by accepting federally enforceable criteria pollutant emissions caps for EU5 (Boiler 5 at the Central Heating Plant) listed below: SO2 = 35.29 tpy - (PSD applicability threshold = 40 tpy) NOx = 8.24 tpy - (PSD applicability threshold = 40 tpy) CO = 0.75 tpy - (PSD applicability threshold = 100 tpy) TSP = 2.55 tpy - (PSD applicability threshold = 25 tpy) PM10 = 2.19 tpy - (PSD applicability threshold = 15 tpy)

EU5 40 CFR 52.21 Avoidance

Yes

Finding: Boiler #5 (EU5) blew a tube in March 2012 and is permanently disabled. 4. The facility netted out of NSR and PSD program

requirements via accepting federally enforceable emissions caps for combined emissions from EU1 through EU10. See Attachment A of Temporary Permit FP-T-0110 for an explanation of the netting analysis and how the criteria pollutant emission caps were established. Facility wide caps do not contain emissions from insignificant boilers, insignificant emergency generators, fuel oil storage sources, and/or miscellaneous insignificant VOC sources. These criteria pollutant emission caps became effective on June 1, 2006, when EU7, EU8, and EU9 were operational and began to emit a particular pollutant, in accordance with 40 CFR 52.21(b)(3)(viii). Criteria pollutant emissions caps for EU1 through EU10 combined for consecutive 12-month periods for the criteria pollutants and sulfuric acid (H2SO4) mist are listed below:

NOx = 77.83 tons per consecutive 12 month period SO2 = 257.20 tons per consecutive 12 month period CO = 106.34 tons per consecutive 12 month period VOC = 25.74 tons per consecutive 12 month period PM10 = 30.81 tons per consecutive 12 month period H2SO4 Mist = 6.90 tons per consecutive 12 month period

EU1 through EU10

40 CFR 52.21 Avoidance & Temporary

Permit FP-T-0110

Yes


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5. The facility is opting out of NOx RACT requirements for emergency generators in Env-A 1211.11 by keeping the combined theoretical potential to emit NOx emissions below 25 tons per consecutive 12 month period by taking a 275 hour per year limitation for each Emergency Generator at the facility. Note that this is more stringent than Env-A 1211.01(j)(1), which calls for restricting hours of operation to less than 500 hours.

EU9, EU10, & EU11

Env-A 1211.01(j) & Temporary

Permit FP-T-0110 Yes

6. All emergency generators at the facility shall only operate: a) As a mechanical or electrical power source and only

when the primary power source for the Facility has been lost during an emergency such as a power outage; or

b) During normal maintenance and testing as recommended by the manufacturer.

EU9, EU10, & EU11

Env-A 1211.02(o) &

Temporary Permit

FP-T-0110 Yes

7. NOx RACT Emission Standards for Combustion Turbines NOx emissions from the Combustion Turbine (CT) shall be less than or equal to 25 ppmvd at 15% oxygen or 0.092 lb/MMBtu while firing natural gas. Note that this is more stringent than the NOx emissions limit in 40 CFR 60 Subpart GG Section 60.332.

EU7 Env-A 1211.06(d) &

Temporary Permit

FP-T-0110

No

Findings: On November 18, 2011, July 2, 2012, November 2, 2012, and December 30, 2012, UNH exceeded the 25 ppm NOx emission limit. UNH reported this to DES via Permit Deviation Reports.

8. NOx RACT Emission Standards for Combustion TurbinesNOx emissions from the CT shall be less than or equal to 65 ppmvd at 15% oxygen or 0.253 lb/MMBtu while firing oil.

EU7 Env-A 1211.06(c)(1)b.2.

& Temporary Permit

FP-T-0110

Yes

Finding: On February 21-23, 2007, stack testing occurred on EU7. Stack test results when EU7 operated on oil indicated that the NOx emissions were below permit limits. The NOx CEMS has not shown any exceedances of the NOx emission limit when EU7 has operated on oil.

9. Visible Emission Standard for Fuel Burning Devices Installed on or Prior to May 13, 1970 No owner or operator shall cause or allow average opacity from fuel burning devices in excess of 40 percent for any continuous 6 minute period in any 60 minute period.

EU1 through EU4 & EU6

Env-A 1202.01 &

Env-A 2002.01 (eff. 4-23-05)

Yes

10. Visible Emission Standard for Fuel Burning Devices Installed After May 13, 1970No owner or operator shall cause or allow average opacity from fuel burning devices in excess of 20 percent for any continuous 6 minute period in any 60 minute period.

EU5, EU7, EU8, EU9, EU10, &

EU11

Env-A 1202.02 &

Env-A 2002.02 (eff. 4-23-05) &

Temporary Permit

FP-T-0110

Yes


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11. Activities Exempt from the Visible Emission Standard For those steam generating units subject to 40 CFR 60, i.e., the CT and Duct Burner (DB) on the Heat Recovery Steam Generator (HRSG), no more than one of the following 2 exemptions shall be taken:

a) During periods of startup, shutdown and malfunction, average opacity shall be allowed to be in excess of 20 percent for one period of 6 continuous minutes in any 60 minute period; or

b) During periods of normal operation, average opacity shall be allowed to be in excess of 20 percent but not more than 27 percent for one period of 6 continuous minutes in any 60 minute period.

EU7 & EU8 Env-A 2002.04(a)

(eff. 4-23-05) & Temporary

Permit FP-T-0110

Yes

12. Activities Exempt from the Visible Emission Standard Exceedances of the opacity standard shall not be considered violations of this chapter if the source demonstrates to the department that such exceedances were the result of the adherence to good boiler operating practices which, in the long term, results in the most efficient or safe operation of the boiler. Exceedances of the opacity standard shall not be considered violations of this chapter if the source demonstrates to the department that such exceedances were the result of the occurrence of an unplanned incident in which the opacity exceedance was beyond the control of the operator and that in response to such an incident, the operator took appropriate steps in conformance with good boiler operating practice to eliminate the excess opacity as quickly as possible.

EU7 & EU8 Env-A 2002.04(d),(f)


Permit FP-T-0110

Yes

13. Particulate Emission Standards for Fuel Burning Devices Installed on or Prior to May 13, 1970 No owner or operator shall cause or allow emissions of particulate matter from fuel burning devices installed on or prior to May 13, 1970 in excess of the rates set forth below, where: For devices with I (maximum gross heat input rate in MMBtu/hr) equal to or greater than 10 but less than 10,000, E (the maximum allowable particulate matter emission rate in lb/MMBtu) shall be calculated by raising I to the –0.166 power, and multiplying the result by 0.880, expressed mathematically in the formula below: E = 0.880 * I-0.166

EU1 through EU4 & EU6

Env-A 2002.06(c)(2) (eff. 4-23-05)

Unknown

Finding: Compliance can only be determined by stack testing, which is not required at this time. 14. Particulate Emission Standards for Fuel Burning Devices

Installed on or After January 1, 1985No owner or operator shall cause or allow emissions of particulate matter from fuel burning devices installed on or after January 1, 1985 in excess of 0.30 lb/MMBtu.

EU5, EU7/EU8,

EU9, EU10, & EU11

Env-A 2002.08(c)(1)


Permit FP-T-0110

Unknown


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Finding: Compliance can only be determined by stack testing, which is not required at this time. 15. The CT emissions shall be limited to less than 0.015

percent sulfur dioxide by volume at 15 percent oxygen and on a dry basis and no fuel shall be burned in the CT which contains sulfur in excess of 0.8 percent by weight

EU7 40 CFR 60 Subpart GG

Section 60.333(a) & (b)

Yes

16. Accidental Release Program Requirements The quantities of regulated chemicals stored at the facility are less than the applicable threshold quantities established in 40 CFR 68.130. 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 which 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.

Facility Wide CAA Section 112(r)(1)

Yes

VI. Compliance with Monitoring and Testing Requirements Table 5 below, taken from permit TV-OP-010, lists the monitoring and testing requirements for the facility, and any deficiencies noted during the evaluation.

Table 5 – Monitoring and Testing Requirements Item

# Parameter Method of Compliance Frequency Applicable Unit

Rule Citation Compliant

1. NOx RACT Annual Boiler

Tune-ups

NOx RACT Annual Boiler Tune-up Annually, the owner or operator shall:

a) Perform an efficiency test using the test procedures specified in Chapter 3, Combustion Efficiency Tables, Taplin, Harry R., Fairmont Press, 1991; and

b) Adjust the combustion process of the boiler in accordance with the procedures specified in Chapter 5, Combustion Efficiency Tables, Taplin, Harry R., Fairmont Press, 1991.

Annually, or within 60 days of

startup if a unit has been out of service

for 12 consecutive months or

longer

EU1 through

EU6

Env-A 1211.05(b)

(1)

Yes


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2. Fuel Monitoring (Natural gas)

Fuel flow monitors and recorders shall be installed, maintained, and operated on the natural gas inlet lines to the CT and DB. The systems shall at a minimum be capable of giving instantaneous flow measurements and recording total daily (continuous 24 hour period) fuel usage for the emissions device. The owner or operator shall follow the manufacturer’s recommended calibration and preventative maintenance procedures.

Instantaneous & Daily

Total Consumption

EU7 & EU8

Temporary Permit

FP-T-0110

Yes

3. Fuel Monitoring (#2 Fuel oil)

A fuel flow monitor and recorder shall be installed, maintained, and operated on the fuel oil inlet line to the CT. The system shall at a minimum be capable of giving instantaneous flow measurements and recording total daily (continuous 24 hour period) fuel usage for the CT. The owner or operator shall follow the manufacturer’s recommended calibration and preventative maintenance procedures.

Instantaneous & Daily

Total Consumption

EU7 Temporary Permit

FP-T-0110

Yes

4. Hours of Operation for the BSEG

A non-resettable hour meter/totalizer shall be installed, maintained, and operated on the BSEG. The system shall be capable of recording and totalizing hours of operation of the BSEG. The owner or operator shall follow the manufacturer’s recommended calibration and preventative maintenance procedures.

Continuous hours of operation

EU9 Temporary Permit

FP-T-0110

Yes


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5. Custom Fuel Monitoring for CT (natural gas)

a) No monitoring of fuel nitrogen is required so long as the facility is supplied with solely pipeline-quality natural gas or LNG.

b) No monitoring of sulfur content is required for pipeline natural gas that meets the definition of natural gas in 40 CFR 60 Section 60.331(u), i.e., is less than or equal to 20 grains of sulfur per 100 cubic feet of natural gas. The owner or operator is required to keep records of the gas quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the gaseous fuel, specifying that the maximum total sulfur content of the fuel is 20.0 grains/100 scf or less. The owner or operator can also use representative fuel sampling and analysis data from its performance test to show the sulfur content of the pipeline natural gas is less than or equal to 20.0 grains/100 scf.

As specified EU7 40 CFR 60 Subpart

GG Section

60.334(h) (3) &

Temporary Permit

FP-T-0110

Yes

6. Custom Fuel Monitoring for CT (#2 Fuel oil)

The owner or operator shall be required to do the following monitoring of No. 2 fuel oil for consumption by the Combustion Turbine: For each delivery of No. 2 fuel oil, the owner or operator shall conduct testing using the appropriate ASTM Method or retain certified delivery tickets from the fuel oil supplier which state the weight percent of sulfur and fuel bound nitrogen content to determine compliance with the sulfur and nitrogen content limitations required by 40 CFR 60 Subpart GG in this permit for liquid fuels.

As specified EU7 Temporary Permit

FP-T-0110

Yes


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7. CT NOx CEMS Requirements

The owner or operator shall install, operate, maintain, and perform quality assurance testing of a CEM system meeting all of the requirements specified in Items 8 through 15 of Table 7a if any of the following conditions exists: The owner or operator of a source chooses to limit its potential to emit by accepting federally enforceable permit conditions that restrict its hours of operation, the type or amount of material combusted, stored, or processed, or its level of production, and continuous emission monitoring is determined by the division to be necessary to ensure that these permit conditions are not violated.

As specified EU7 Env-A 808.02(a) (2) (eff.

10-31-02) &

Temporary Permit

FP-T-0110

Yes


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8. CT NOx CEMS Minimum Specifications for CEM Systems

a) A CEM system for measuring gaseous emissions shall average and record the data for each calendar hour;

b) All CEM systems, opacity and gaseous measuring included, shall: 1) Include a means to display

instantaneous values of percent opacity and gaseous emission concentrations; and

2) Complete a minimum of one cycle of operation, which shall include measurement, analyzing, and data recording for each successive 5-minute period for systems measuring gaseous emissions and each 10-second period for systems measuring opacity, unless a longer time period is approved in accordance with Env-A 809;

c) A stack volumetric flow measuring device required to be installed after January 1, 1992, shall meet the following requirements: 1) All differential pressure flow

monitors shall have an automatic blow-back purge system installed, and in wet stack conditions, shall have the capability for drainage of the sensing lines; and

2) The stack flow monitoring system shall have the capability for manual calibration of the transducer while the system in on-line and for a zero check; and

d) Alternatives to in-stack flow monitoring devices for determination of stack volumetric flow rate may be used if the owner or operator provides the Division with technical justification that the alternative can meet the same requirements for data availability, data accuracy, and quality assurance as an in-stack device.

As specified EU7 Env-A 808.03(a), (c), (d), & (e) (eff.

10-31-02) &

Temporary Permit

FP-T-0110

Yes


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9. NOx CEM QA/QC Plan Requirements

The owner or operator is required to develop a QA/QC plan for the NOx CEM system. A copy must be filed with the Division within 30 days of completion of the performance specification testing of the NOx CEM. It must be reviewed at least once annually and updated. Within 30 days of completion of the QA/QC plan annual review, the owner or operator must certify in writing to the Division 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 reason for each change. The QA/QC plan shall be considered an update to the CEM monitoring plan required by Env-A 808.04.

As specified EU7 Env-A 808.06(a)

& (c) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

No

Findings: UNH has not filed with DES, documentation on QA/QC plans for 2012 or 2013. In accordance with Env-A 808.06 (c)(5), documentation on QA/QC Plan must be filed no later than April 15 of each year.

10. NOx CEM General Audit Requirements

a) Required quarterly audits shall be done anytime during each calendar quarter, but successive quarterly audits shall occur no more than 4 months apart;

b) Within 30 days following the end of each quarter, the owner or operator of the source shall submit to the Division a written summary report of the results of all required audits that were performed in that quarter, with the report format for the NOx CEM system conforming to that presented in 40 CFR 60 Appendix F, Procedure 1, Section 7;

c) The owner or operator shall notify the Division at least 30 days prior to the performance of a RATA;

d) The Division shall require rescheduling of any RATA if the staff necessary to observe the audit are not available; and

e) The owner or operator shall provide at least two weeks notice prior to any other planned audit or test procedure.

As specified EU7 Env-A 808.07(a)-

(e) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes


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11. Audit Requirements for Gaseous CEM Systems

For a system monitoring gaseous emissions of SO2, NOx, O2 or CO2, the quality assurance requirements and procedures described in 40 CFR 60, Appendix F, shall apply, with the following additions and clarifications for Procedure 1 of Appendix F: a) The owner or operator shall inform

the division of all out of control periods, as defined in Appendix F, section 4.3, and Env-A 808.01(g), in the emission reports required pursuant to Env-A 808.11;

b) The owner or operator may perform a RAA, as defined in 40 CFR 60, Appendix F, in place of a CGA; and

c) For CEM systems where CGA audits cannot be performed, the owner or operator shall perform RAA audits in place of the CGA.

As specified EU7 Env-A 808.08(a) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

No

Findings: UNH has performed the required CGA's, however, for the following quarters, UNH has not submitted the reports to DES; 2011: Quarters 1, 2, and 3; 2012: Quarters 2 and 3; 2013: Quarters 1 and 2. This is as required in accordance with Env-A 808.07(b). UNH submitted to DES all of the late CGA Reports on August 20, 2013. (Late) On August 20, 2013, DES received from UNH the CGA report for Quarter 3 of 2013. (On time)


The owner or operator of a stationary source determining compliance with a mass flow emissions limit by using a stack flow volumetric monitor or a fuel flow meter with O2/CO2 measurements to calculate heat input or stack flow rate, shall conduct annually a minimum 9-run RATA with the relative accuracy calculated in the units of the mass emissions measurement as specified in 40 CFR 60, Appendices B and F.

As specified EU7 Env-A 808.08(d) (eff. 10-31-02) &

Temporary Permit

FP-T-0110 Yes


For a stationary source using a stack volumetric flow monitor for the mass flow emissions calculation, the owner or operator shall also perform one of the audit options as specified in Env-A 808.08(f)(1) or (2).

As specified EU7 Env-A 808.08(f) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

Not Applicable

Finding: UNH does not have stack flow monitors.


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14. Data Availability Requirements

The owner or operator of a source with a CEM shall operate the NOx CEM at all times during operation of the CT, except for periods of CEM breakdown, repairs, calibration checks, preventative maintenance, and zero/span adjustments. The percentage CEM data availability for opacity and all gaseous concentration monitors shall be maintained at a minimum of 90% on a calendar quarter basis. The percentage CEM data availability for opacity and all gaseous concentration monitors shall be maintained at a minimum of 75% for any calendar month. The percentage CEM data availability is calculated as specified in Env-A 808.10(d). If the percentage data availability requirements can’t be met for any calendar quarter, the owner or operator is required to follow the procedures in Env-A 808.10(e)(1) and (2). If the percentage data availability requirements can’t be met for any 2 consecutive calendar quarters, the owner or operator is required to follow the procedures in Env-A 808.10(f)(1) and (2) for installing a replacement CEM or Env-A 808.10(g).


(g) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

No

Findings: For the second quarter of 2011, UNH failed to meet the data availability requirements for the NOx CEMS. UNH reported this to DES via a Deviation Report.

15. CEM Valid Averaging Periods

The number of hours of valid CEM data required for determining a valid averaging period for the different emission standard periods shall be: a) For a 24-hr standard emission

standard period, 18 hours of valid data.


(e) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes

16. General Stack Testing Requirements

The owner or operator shall conduct visible and gaseous emissions testing conforming to the following: a) A compliance stack emissions test

shall conform to the following: 1) The general requirements of

40 CFR 60.8(a), (b), (d), (e), and (f); and

2) The test methods contained in 40 CFR 60 Appendix A, 40 CFR 51 Appendix M, or any other EPA-promulgated stack test method.

Initial performance

test

EU7 & EU8

Env-A 802.02(a)-(f) (eff. 10-31-02) &

Temporary Permit

FP-T-0110 Yes


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b) An owner or operator shall sample emissions at locations and sampling points that will provide representative measurements of the actual emissions during source operation at the time of the test.

c) The owner or operator shall perform a stratification check at each measurement location where a determination of a gas concentration is required.

d) A stratification check shall be accomplished by measuring the pollutant or diluent, oxygen or carbon dioxide gas concentration in accordance with the EPA Emission Measurement Technical Information Center Guideline Document, GD-025, Determination of the Presence of Stratification of Gaseous Pollutant and Diluent Emissions for Continuous Emission Monitor or Reference Method Relative Accuracy Locations, June 21, 1994.

e) If stratification does not exist, a single point gas/diluent measurement location shall be acceptable within the inner 50 percent area of the duct or stack cross section.

f) If stratification exists, the owner or operator shall obtain samples either at locations across the stack diameter equivalent to those specified in 40 CFR 60, Appendix B, Performance Specification 2, paragraph 3.2, or the locations specified in 40 CFR 60, Appendix A, Method 1.

17. Pre-test Notice a) At least 30 days prior to the commencement of source testing, the owner or operator shall notify the division, of the date(s) of any planned compliance stack testing.

b) The division shall require the rescheduling of any compliance stack emissions test if the staff necessary to observe the test, are not available.

Initial performance

test

EU7 & EU8

40 CFR 60 Subpart A,

Section 60.8(d)

Yes


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18. Pre-Test Protocol

At least 30 days prior to the commencement of testing, the Facility shall submit to the Division a pretest protocol with the information in Env-A 802.04(a) through (o).

Initial performance

test

EU7 & EU8

Env-A 802.04

(eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes

19. Pre-Test Meeting

At least 15 days prior to the test date, the owner or operator and any contractor retained by the owner or operator to conduct the test shall meet with a Division representative or over the telephone. The details of the test, the testing schedule, and the process conditions under which the data shall be collected shall be finalized at the pre-test meeting. A pre-test meeting may be held less than 15 days prior to the test date so long as implementation of any testing or operation changes resulting from the meeting can be carried out prior to the scheduled test date and the scheduled test integrity is not jeopardized.

Initial performance

test

EU7 & EU8

Env-A 802.05

(eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes

20. Safe Access to Sampling Platforms

The owner or operator must provide for safe access to sampling stations and provide sampling stations in accordance with 40 CFR 60 Subpart A, Section 60.8(e).

Initial performance

test

EU7 & EU8


Section 60.8(e)

Yes

21. Number of Runs for a Complete Test

Each performance test shall consist of three separate runs using the applicable test method.

Initial performance

test

EU7 & EU8


Section 60.8(f)

Yes


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22. Repeating a Compliance Stack Test

An owner or operator that repeats a compliance stack test on the same source shall not be required to submit another pre-test protocol or attend another pre-test meeting as specified in Env-A 802.04 and Env-A 802.05, provided that the following conditions are met: a) The owner or operator uses the same

stack testing contractor; b) The owner or operator follows all

stack test and plant operating conditions specified in the previously accepted pre-test protocol or any deviations from the previously accepted pre-test protocol are specified in detail in the letter described in d) below;

c) The division approved the previous stack test as submitted by the owner or operator and the stack testing contractor; and

d) The owner, operator, or stack testing contractor submits a letter to the division referencing the previously approved pre-test protocol and pre-test meeting and identifying in detail any deviations from the previously accepted pre-test protocol or pre-test meeting.

Initial performance

test

EU7 & EU8

Env-A 802.06(a)-

(d) (eff. 10-31-02)

& Temporary

Permit FP-T-0110

Yes

23. Scheduling Changes

a) The owner or operator shall notify the division by telephone, fax, or electronic mail prior to any changes in the testing schedule for a compliance stack test.

b) The owner or operator shall obtain prior approval from the division, which shall be based on staff availability, of any new date for a compliance stack test.

Initial performance

test

EU7 & EU8

Env-A 802.07(a)

& (b) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes

24. Calibration Data for Stack Sampling Equipment

a) The owner or operator shall provide calibration data for any sampling equipment used during the compliance stack testing to the division upon request during the day of testing.

b) The owner or operator shall provide copies of all calibration and field test data taken during the testing, including failed runs, to the division upon request.

Initial performance

test

EU7 & EU8

Env-A 802.08(a)

& (b) (eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes


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25. Use of Alternative Methods During a Test

The Division shall approve deviations from the agreed-upon test method or pre-test protocol if the following criteria are met: a) The owner or operator informs

division personnel assigned to the stack test of the following: 1) The deviation from the testing

method or planned operational mode of the source;

2) The reason(s) for the deviation;

3) The implications of such a deviation; and

4) The owner or operator provides technical justification showing that allowance of such deviation will not affect the accuracy of the compliance stack emissions test.

Initial performance

test

EU7 & EU8

Env-A 802.09

(eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes

26. Operating Conditions During a Stack Emission Test

In accordance with 40 CFR 60 Subpart GG and revisions contained in the Federal Register dated April 14, 2003 (pages 17990 to 18005), the facility is required to test the CT while firing No. 2 fuel oil without the HRSG on line at 90 to 100 percent peak load for three runs. The facility will repeat this test procedure with the CT while firing natural gas without the HRSG on line. In addition, DES is requiring the facility to test the CT and duct burner combined with the CT firing No. 2 fuel oil at 90 to 100 percent peak load and the duct burner at 100 percent load on natural gas for three runs. Finally, the facility will test the CT and duct burner combined with the CT firing natural gas at 90 to 100 percent peak load and the duct burner at 100 percent load on natural gas for three runs. The facility shall test for NOx, CO, %O2 or CO2, PM10, and H2SO4 mist on the CT and duct burner tests.

Initial performance

test

EU7 & EU8


Section 60.8(c)

Yes

27. Report Submission Requirements

The owner or operator shall submit the stack test emissions report containing all of the information in Env-A 802.11(c)(1) through (8) to the Division within 60 days of the completion of the stack testing.

Within 60 days of

completion of initial

performance test

EU7 & EU8

Env-A 802.11

(eff. 10-31-02) &

Temporary Permit

FP-T-0110

Yes


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28. Monitoring Electrical

Power Generation

The owner or operator shall monitor electrical power generation from its Combustion Turbine in accordance with either Env-A 3705.01(b)(1) or (2). All power generation monitors shall be operated and maintained in accordance with the operating and maintenance procedures specified by the manufacturer.

Continuous EU7 Env-A 3705.01(b)

& Temporary

Permit FP-T-0110

Yes

29. Sulfur Content of Liquid

Fuels

The owner or operator shall conduct testing using the appropriate ASTM methods or retain certified delivery tickets which state the weight percent of sulfur for each delivery of fuel oil to determine compliance with the sulfur content limitation provisions in this permit for liquid fuels.

For each delivery

Facility Wide

Env-A 806.02 &

Env-A 806.05

(eff. 10-31-02)

Yes

Table 7 below, taken from permit TP-B-0531, lists the monitoring and testing requirements for the facility, and any deficiencies noted during the evaluation.


# Applicable

Unit Pollutant/ Parameter Method of Compliance Frequency Rule

Citation Compliant

1 EU14 EU15 EU18 EU19

NOx CO SO2

VOC

Stack Testing Requirements: a. A compliance stack emissions test

shall conform to the following: i. The procedures specified in

Env-A 802; ii. The general requirements of 40

CFR 60.8(a), (b), (d), (e), and (f); and

iii. The test methods contained in 40 CFR 60, Appendix A, 40 CFR 51, Appendix M, or any other stack test method promulgated by the USEPA, or any alternative, conditional or other test method approved by the USEPA, or any alternative method approved by the department in accordance with Env-A 809.

For each required stack test

Env-A 802.02

(effective 10-31-2010)

Yes


of 72


# Applicable


Citation Compliant

2 EU14 EU15

NOx CO

Compliance Stack Testing for NOx RACT: a. The owner or operator shall

determine compliance with the NOx emission limits specified in Table 5 of this permit for the Reciprocating Engine #1 (EU14) and Reciprocating Engine #2 (EU15) by conducting stack testing every three years. Compliance stack testing shall be conducted in accordance with Env-A 802.

b. The following test methods, or Division approved alternatives, shall be used as applicable: i. Method 7, 7A, 7C, 7D or 7E as

described in 40 CFR 60, Appendix A, to determine NOx concentrations in stack gases;

ii. Method 10 as described in 40 CFR 60, Appendix A, to determine CO concentrations in stack gases;

iii. Methods 1 and 2, 2C, 2F, 2G, or 2H, as described in 40 CFR 60, Appendix A, to determine the exit flow rate of stack gases;

iv. Method 3 or 3A as described in 40 CFR 60, Appendix A, to determine carbon dioxide, oxygen, excess air and molecular weight (dry basis) of stack gases; and

v. Method 4 as described in 40 CFR 60, Appendix A, to determine the volume fraction of water vapor in stack gases.

Once every 3 years from

date of previous

NOx RACT compliance stack test

Env-A 803.03 Env-A 803.04

(effective 10-31-2010)

Yes


of 72


# Applicable


Citation Compliant

3 EU16 EU17

Net heating value

For the performance test required in Table 6, Item 145, the net heating value of the combusted landfill gas as determined in Table 6, Item 14(a) is calculated from the concentration of methane in the landfill gas as measured by Method 3C. A minimum of three 30-minute Method 3C samples are determined. The measurement of other organic components, hydrogen, and carbon monoxide is not applicable. Method 3C may be used to determine the landfill gas molecular weight for calculating the flare gas exit velocity under Table 7, Item 4.

Within 180 days of

issuance of the amended

permit

Env-A 604.01

Yes

4 EU16 EU17

Actual exit velocity

The actual exit velocity of a flare shall be determined by dividing the volumetric flow rate (in units of standard temperature and pressure), as determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross sectional area of the flare tip.

Within 180 days of issuance of the amended permit

Env-A 604.01

Yes

5 EU16 EU17

Volume-percent of hydrogen

The volume-percent of hydrogen, on a wet basis, listed in Table 6, Item 14 b, shall be calculated by using the American Society for Testing and Materials (ASTM) Method D1946-77.

If the owner or operator chooses to follow Table 5, Item 15 b., then within 180 days of switching to that method

Env-A 604.01

Not Applicable

Finding: UNH is using method specified in Table 5, Item 15(a). 6 EU18 NOx

CO SO2 VOC

Compliance Stack Testing:a. The owner or operator shall

determine compliance with the NOx, CO, SO2, and VOC emission limits specified in Table 5 of this permit for the Thermal Oxidizer by conducting stack testing every three years. Compliance stack testing shall be conducted in accordance with Env-A 802.



ii. Method 10 as described in 40 CFR 60, Appendix A, to

Once every 3 years from date of previous NOx RACT compliance stack test

Env-A 803.03 Env-A 803.04 (effective 10-31-2010)

Yes


of 72


# Applicable


Citation Compliant

determine CO concentrations in stack gases;

iii. Methods 6 or 6C, as described in 40 CFR 60, Appendix A, to determine SO2 concentrations in stack gases;

iv. Method 25 or 25A for total gaseous non-methane organic compound emissions;

v. Methods 1 and 2, 2C, 2F, 2G, or 2H, as described in 40 CFR 60, Appendix A, to determine the exit flow rate of stack gases;

vi. Method 3 or 3A as described in 40 CFR 60, Appendix A, to determine carbon dioxide, oxygen, excess air and molecular weight (dry basis) of stack gases; and

vii. Method 4 as described in 40 CFR 60, Appendix A, to determine the volume fraction of water vapor in stack gases.

7 EU14 EU15 EU16 EU17 EU18

Sulfur content of gaseous

fuel (landfill gas)

For the purpose of determining the sulfur content in grains of sulfur per 100 cubic feet of landfill gas, the owner or operator shall use one of the following test methods or Division approved alternatives: a. ASTM D 1072-06; b. ASTM D 4084-07; c. ASTM D 3246-05; d. ASTM D 5504-08; or e. ASTM D 6228-98.

In accordance with the monitoring schedules specified in Table 7b, Items 17 and 18 below

Env-A 806.03(a)

Yes

8 EU14 EU15 EU18 EU19

Opacity Opacity Measurements: a. The owner or operator shall conduct

opacity measurements following the procedures set forth in 40 CFR 60 Appendix A, Method 9, Visual Determination of the Opacity of Emissions from Stationary Sources.

b. The measurements in (a) above shall be taken over 60 minutes during normal operations of the device.

Upon request by DES or USEPA or as determined necessary by the owner or operator

Env-A 807.02

Not Applicable

Finding: DES or EPA has not requested that UNH meet this requirement.


of 72


# Applicable


Citation Compliant

9 EU16 EU17

Opacity Opacity Measurements: a. The owner or operator shall conduct

measurements of the amount of time that any visible fugitive emissions occur during an observation period by following 40 CFR 60, Appendix A, Method 22 – Visual Determination of Fugitive Emissions from Material Sources and Smoke Emissions from Flares.

b. The observation period for (a) above is 2 hours and shall be used according to Method 22.

Upon request by DES or USEPA or as determined necessary by the owner or operator

Env-A 807.05

Not Applicable

Finding: DES or EPA has not requested that UNH meet this requirement. 10 Facility wide Approval of

alternate methods or

requirements

Approval of Alternate Methods or Requirements: a. The owner or operator of a source

who wishes to obtain approval of an alternate method or requirement (proposed alternate) shall file with the department a written request, electronically or on paper, that contains the following information: i. The name, mailing address,

daytime telephone number, and e-mail address of the owner or operator requesting approval for the proposed alternate;

ii. The name and location of the source at which the proposed alternate will be implemented;

iii. The identity of the specified method or requirement and the reason why it can not be used as directed;

iv. A description of the proposed alternate;

v. The identity of the compound(s) that is to be tested or controlled or the equipment that is to be addressed by the proposed alternate; and

vi. Technical data and information demonstrating that the purpose of the specified method or requirement will be achieved by the proposed alternate and that the proposed alternative produces results that are at

Upon request by owner or operator

Env-A 809.01 Env-A 809.02 (effective 10-31-2010) (formerly Env-A 809.01 (a) and (b))

Not Applicable


of 72


# Applicable


Citation Compliant

least as precise and accurate as those produced by the specified method or requirement.

b. Within 60 days of receipt of a request that meets the requirements of (a) above, the department shall approve the request if the department determines that the proposed alternate: i. Achieves the purpose of the

specified method or requirement; and

ii. Produces results that are at least as precise and accurate as those produced by the specified method or requirement.

c. The department shall notify the person who submitted the request and EPA of the decision in writing. If the request is denied, the department shall specify the reason(s) for the denial.

Finding: UNH has not requested approval of any alternate methods or requirements. 11 Facility wide Alternative

Methods for Federal

Standards

Alternative Methods for Federal Standards: An owner or operator seeking approval of modifications to test methods or of alternate test methods for compliance with federal standards, such as those specified in 40 CFR 60, 61, 63, and 75, shall submit the request to EPA for approval.

Under request by owner or operator

Env-A 809.03 (effective 10-31-10) (formerly Env-A 809.02)

Not Applicable

Finding: UNH has not requested approval of any alternative methods for Federal standards. a. The owner or operator shall monitor

and record the temperature in the combustion chamber.

Continuous Yes

12 PCE01 EU18

Thermal Oxidizer Combustion Chamber Temperature

b. If the temperature reading is less than the minimum specified in Table 6, Item 11 a., then inspect the unit and take corrective action to raise the temperature.

As noted

Env-A 906

Yes


of 72


# Applicable


Citation Compliant

13 PCE01 EU18

Thermal Oxidizer

Inspection

Conduct a visual external integrity inspection of the thermal oxidizer. a. The inspection shall include an

evaluation of whether all emissions are being vented through the dedicated stack exit.

b. The inspection shall be conducted by plant personnel familiar with the operation of the oxidizer and associated equipment.

Annually and as conditions indicate it inspection is warranted

RSA 125-C:6, XI

Yes

14 EU14 EU15 EU19

Electrical Power

Generation

Determine electrical power generation by either of the following methods: a. By calculating actual electrical

power generation in MW-hr by multiplying the heat input in MMBtu obtained from fuel use records by 0.10 MW-hr/MMBtu; or

b. By monitoring electrical power generation in kW-hr using one of the monitors specified in Env-A 3705.01(b)(1).

Continuous Env-A 3705.01

Yes

15 EU19 NOx a. The owner or operator must perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance. If the NOx emission result from the performance test is less than or equal to 75 percent of the NOx emission limit for the turbine (the limit is 96 ppm @15% O2), the owner or operator may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOx emission limit for the turbine, the owner or operator must resume annual performance tests.

b. As an alternative to (a) above, the owner or operator may install, calibrate, maintain and operate one of the following continuous monitoring systems: i. Continuous emission

monitoring as described in 40 CFR §60.4335(b) and 40 CFR §60.4345, or

ii. Continuous parameter monitoring as follows:

Continuous 40 CFR § 60.4340

No


of 72


# Applicable


Citation Compliant

A. For a diffusion flame turbine without add-on selective catalytic reduction (SCR) controls, the owner or operator must define parameters indicative of the unit's NOx formation characteristics, and you must monitor these parameters continuously.

B. For any lean premix stationary combustion turbine, the owner or operator must continuously monitor the appropriate parameters to determine whether the unit is operating in low-NOx mode.

Findings: NOx RACT testing on the Solar Turbine (EU19) is required every two years and the latest test was due to be conducted by November 2011. The required test was not done timely and was subsequently conducted on March 23, 2012. Test results indicate that emissions of NOx. CO, and SO2 meet the permit requirements. UNH reported this to DES via a Deviation Report. 16 EU19 NOx

CO Compliance Stack Testing for NOx RACT: a. The owner or operator shall

determine compliance with the NOx emission limits specified in Table 5 of this permit for the Supplemental Turbine by conducting stack testing every three years. Compliance stack testing shall be conducted in accordance with Env-A 802.



ii. Method 10 as described in 40 CFR 60, Appendix A, to determine carbon monoxide concentrations in stack gases; and

iii. Method 3 or 3A as described in 40 CFR 60, Appendix A, to determine carbon dioxide, oxygen, excess air and molecular weight (dry basis) of stack gases.

Once every 3 years from date of previous NOx compliance stack test.

Env-A 803.03 Env-A 803.04 (effective 10-30-2010)

Yes


of 72


# Applicable


Citation Compliant

c. The owner or operator may use Method 20 as described in 40 CFR 60, Appendix A, in lieu of the methods identified in b. above, to determine NOx concentrations in stationary gas turbine stack gases.

17 EU19 Sulfur content of turbine fuel

Determining the total sulfur content of the turbine combustion fuel a. The owner or operator must monitor

the total sulfur content of the fuel being fired in the turbine, except as provided in Item (b) below. The sulfur content of the fuel must be determined using total sulfur methods described in §60.4415. Alternatively, if the total sulfur content of the gaseous fuel during the most recent performance test was less than half the applicable limit, ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see 40 CFR §60.17), which measure the major sulfur compounds, may be used.

b. The owner or operator may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed potential sulfur emissions of 0.060 lb SO2/MMBtu heat input. The following source of information must be used to make the required demonstration: i. Representative fuel sampling

data which show that the sulfur content of the fuel does not exceed 0.060 lb SO2/MMBtu heat input. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to 40 CFR Part 75 is required.

c. If the owner or operator elects not to demonstrate sulfur content using the option in (b) above (40 CFR §60.4365), and the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous fuel must be determined and recorded once per unit

As specified within regulation

40 CFR §60.4360 40 CFR §60.4365 40 CFR §60.4370

Yes


of 72


# Applicable


Citation Compliant

operating day.

18 EU19 Sulfur content of turbine fuel

Custom schedules for determination of the total sulfur content of gaseous fuels a. Notwithstanding the requirement of

Item 16 c. above of this table, the owner or operator may develop custom schedules for determination of the total sulfur content of gaseous fuels, based on the design and operation of the affected facility and the characteristics of the fuel supply. Except as provided in paragraphs (b)(i) and (b)(ii) below of this permit condition, custom schedules shall be substantiated with data and shall be approved by the Administrator before they can be used to comply with the standard in 40 CFR §60.4330.

b. The two custom sulfur monitoring schedules set forth in paragraphs (i) through (iv) and in paragraph (c) below are acceptable without prior Administrative approval: i. The owner or operator shall

obtain daily total sulfur content measurements for 30 consecutive unit operating days, using the applicable methods specified in this subpart. Based on the results of the 30 daily samples, the required frequency for subsequent monitoring of the fuel's total sulfur content shall be as specified in paragraph (b)(ii), (iii), or (iv) below, as applicable.

ii. If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, subsequent sulfur content monitoring may be performed at 12-month intervals. If any of the samples taken at 12-month intervals has a total sulfur content greater than half but less than the applicable limit, follow the procedures in paragraph (b)(iii) below. If any measurement

As specified within regulation

40 CFR §60.4370

Not Applicable


of 72


# Applicable


Citation Compliant

exceeds the applicable limit, follow the procedures in paragraph (b)(iv) below.

iii. If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than the applicable limit, but none exceeds the applicable limit, then: A. Collect and analyze a

sample every 30 days for 3 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (b)(iv) below. Otherwise, follow the procedures in paragraph (b)(iii)(B) below.

B. Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (b)(iv) below. Otherwise, follow the procedures in paragraph (b)(iii)(C) below.

C. Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (b)(iv) below. Otherwise, continue to monitor at this frequency.

iv. If a sulfur content measurement exceeds the applicable limit, immediately begin daily monitoring according to paragraph (b)(i) above. Daily monitoring shall continue until 30 consecutive daily samples, each having a sulfur content no greater than the applicable limit, are obtained. At that point, the applicable procedures of paragraph (b)(ii) or (iii)


of 72


# Applicable


Citation Compliant

above shall be followed. c. The owner or operator may use the

data collected from the 720-hour sulfur sampling demonstration described in section 2.3.6 of Appendix D to 40 CFR Part 75 to determine a custom sulfur sampling schedule, as follows: i. If the maximum fuel sulfur

content obtained from the 720 hourly samples does not exceed 20 grains/100 scf, no additional monitoring of the sulfur content of the gas is required, for the purposes of 40 CFR Part 60 compliance.

ii. If the maximum fuel sulfur content obtained from any of the 720 hourly samples exceeds 20 grains/100 scf, but none of the sulfur content values (when converted to weight percent sulfur) exceeds half the applicable limit, then the minimum required sampling frequency shall be one sample at 12 month intervals.

iii. If any sample result exceeds half the applicable limit, but none exceeds the applicable limit, follow the provisions of paragraph (b)(iii) above.

iv. If the sulfur content of any of the 720 hourly samples exceeds the applicable limit, follow the provisions of paragraph (b)(iv).

Finding: UNH proposed exercising the exemption option that exists under 40 CFR 60, Subpart KKKK (§60.4365(b)) which is also allowed for in 40 CFR 60, Subpart GG (§60.334(h)(3)), in order to demonstrate that the sulfur content of the processed landfill gas going to the two turbines in Durham does not exceed 0.06 lb SO2/MMBtu heat content. In addition, these requirements cite section 2.3.2.4 of Appendix D to Part 75 for documentation that a fuel is natural gas. UNH provided documentation and EPA concurred (email from EPA dated February 12, 2010) with the analysis that the processed landfill gas coming from the Rochester plant meets the definition of natural gas.


of 72


# Applicable


Citation Compliant

19 EU16 EU17

Flame Presence

The owner or operator shall install, calibrate, maintain, and operate according to the manufacturer’s specifications the following equipment: a. A heat sensing device, such as an

ultraviolet beam sensor or thermocouple, at the pilot light or the flame itself to indicate the continuous presence of a flame.

b. A device that records flow to or bypass of the flare. The owner or operator shall either:

i. Install, calibrate, and maintain a gas flow rate measuring device that shall record the flow to the control device at least every 15 minutes; or

ii. Secure the bypass line valve in the closed position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism shall be performed at least once every month to ensure that the valve is maintained in the closed position and that the gas flow is not diverted through the bypass line.

Continuous Env-A 604.01

Yes

Finding: The flares do not have a bypass line. 20 PCE06 Operational

Parameters of the

Preliminary Treatment

Unit

Monitoring Plan for the Preliminary Treatment Unit: The owner or operator shall provide information describing the operation of the Preliminary Treatment Unit, the operating parameters that would indicate proper performance, and appropriate monitoring procedures to DES for review and approval.

Within 60 days of issuance of the amended permit

Env-A 810

Yes

21 EU16 EU17 PCE06

Startup, Shutdown,

and Malfunction Plan (SSM

Plan)

Startup, Shutdown, and Malfunction Plan (SSM Plan): The owner or operator shall develop a written SSM Plan which contains the following elements, at a minimum: a. Detailed procedures for operating

and maintaining the source during periods of SSM; and

b. A program of corrective action for malfunctioning process, air

Submit to the Division within 60 days of issuance of the amended permit

Env- A 906

Yes


of 72


# Applicable


Citation Compliant

pollution control, and monitoring equipment used to comply with the requirements of Table 6, Items 12 through 16.

The purpose of the SSM Plan is to: a. Ensure that, at all times, the owner

or operator operates and maintains each affected source, including associated air pollution control and monitoring equipment, in a manner which satisfies the general duty to minimize emissions established in Table 6, Item 17;

b. Ensure that the owner or operator is prepared to correct malfunctions as soon as practicable after their occurrence in order to minimize excess emissions of hazardous air pollutants; and

c. Reduce the reporting burden associated with periods of SSM (including corrective action taken to restore malfunctioning process and air pollution control equipment to its normal or usual manner of operation).

VII. Compliance with Recordkeeping Requirements Table 6 below, taken from permit TV-OP-010, lists the recordkeeping requirements for the facility, and any deficiencies noted during the evaluation.

Table 6 –Recordkeeping Requirements Item

# Applicable Requirement Duration/ Frequency

Applicable Unit


1. Retention of Records

The owner or operator shall retain records of all required monitoring data, recordkeeping and reporting requirements, and support information for a period of at least 5 years from the date of origination.

Retain for a minimum of 5

years

Facility Wide

Env-A 902.01 & 40 CFR

70.6(a)(3)(ii)(B) Yes


of 72



Applicable Unit


2. General Recordkeeping Requirements for Combustion Sources

For each fuel burning device at the facility, the owner or operator shall keep records of fuel utilization in accordance with the following:

a) Hours of operation of each combustion device;

b) Fuel consumption; c) Fuel type (e.g., natural gas, liquefied

petroleum gas, No. 2 fuel oil, and diesel fuel);

d) Viscosity (for liquid fuels); e) Sulfur content of any:

1 . Gaseous fuel burned in terms of grains sulfur per scf fuel, or percent sulfur by weight, calculated as hydrogen sulfide at standard temperature and pressure; and

2. Liquid fuel burned in terms of percent sulfur by weight.

Monthly Facility Wide

Env-A 903.03 (eff. 10-21-03) & Temporary

Permit FP-T-0110

Yes

3. General Recordkeeping Requirements for Sources with CEMS

The owner or operator of a stationary source with a certified continuous emission monitoring system subject to Env-A 800, shall maintain records in accordance with the provisions of Env-A 800, and all applicable federal regulations.

On a continuous

basis

EU7 Env-A 903.04 (eff. 10-21-03) & Temporary



of 72



Applicable Unit


4. General NOx Recordkeeping Requirements:

The owner or operator of any stationary source, area source, or device subject to this part, shall record the following information and maintain such records at the facility:

a) Identification of each combustion device;

b) Operating schedule during the high ozone season for each combustion device identified in a), above, including: 1. Hours of operation per calendar

month; 2. Days of operation per calendar

month; 3. Number of weeks of operation; 4. Type and amount of fuel burned

for each combustion device; 5 . Heat input rate in million BTUs

per hour; and 6. The following NOx emission data:

a. Actual NOx emissions from each combustion device identified in a) above for:

1) Each calendar year, in tons; and

2) A high ozone season day during that calendar year, in pounds per day; and

c) The emission factors and the origin of the emission factors used to calculate the NOx emissions.

On a continuous

basis

Facility Wide


Permit FP-T-0110

Yes

5. Additional Recordkeeping Requirements

The owner or operator shall maintain a 12-month running total record of emissions of NOx, SO2, CO, PM10, VOC, and H2SO4 mist from EU1 through EU10 combined, for the purpose of demonstrating that emissions of these pollutants are below the caps in Item 4 of Table 4a, which the facility took to net out of Non-attainment New Source Review and Prevention of Significant Deterioration program requirements.

On a continuous

basis

EU1-EU10 Env-A 906 (eff. 4-23-99) & Temporary

Permit FP-T-0110

Yes


of 72



Applicable Unit


6. NOX RACT Annual Boiler Tune-ups

Maintain in a permanently bound log book the following information:

a) The date(s) on which: 1. The efficiency test was conducted;

and 2. The combustion process was last

adjusted. b) The name(s), title, and affiliation of

the person(s) who: 1. Conducted the efficiency test; and 2. Made the adjustments.

c) The NOx emission concentration, in ppmvd, corrected to 15% oxygen, after the adjustments are made;

d) The CO emission concentration, in ppmvd, corrected to 15% oxygen, after the adjustments are made;

e) The opacity readings; and f) Any other information required by

Env-A 903, Env-A 905, and Env-A 909.

On a continuous

basis

EU1-EU6 Env-A 1211.05(b)(2)

Yes

7. a) The owner or operator shall maintain calendar monthly records of actual NOx emissions in accordance with the methods set forth in Env-A 620.

b) The owner or operator shall maintain calendar monthly records of power generation from the CT in accordance with the following: 1. The measurements of power

generation as output on an instrument recorder;

2. The number of hours of operation of the NOx-emitting generation source;

3. The number of hours of downtime of the power generation monitoring system, if applicable, during the time period when the NOx-emitting generation source is in operation;

4. Fuel usage; and 5. The frequency and results of

calibrations performed, as applicable.

Monthly EU7 Env-A 3706.01 (eff. 12-20-01) & Temporary

Permit FP-T-0110

Yes


of 72



Applicable Unit


8. The owner or operator will calculate the NOx emissions reduction fee by taking the total tons of NOx emissions calculated in accordance with Env-A 3704 and multiplying by the NOx emissions reduction fee in dollars per ton for the appropriate time period from Table 3707-1.

Annually EU7 Env-A 3707.03 (eff. 12-20-01) & Temporary

Permit FP-T-0110

Yes

9. The owner or operator shall maintain records of:

a) The occurrence and duration of any startup, shutdown, or malfunction in the operation of the CT and HRSG Unit; or

b) Any periods during which a continuous monitoring system or monitoring device is inoperative.

As stated EU7 & EU8 40 CFR 60 Subpart A

Section 60.7(b)

Yes

10. The owner or operator shall maintain a file of all measurements, including:

a) Continuous monitoring system, monitoring device (fuel flow meter), and performance testing measurements;

b) All continuous monitoring system performance evaluations;

c) All continuous monitoring system or monitoring device calibration checks;

d) Adjustments and maintenance performed on these systems or devices; and

e) All other information required by this part recorded in a permanent form suitable for inspection.

5 year record retention

EU7 & EU8 40 CFR 60 Subpart A

Section 60.7(f)

Yes

11. Monitoring/Testing Data

The owner or operator shall maintain records of monitoring and testing requirements as specified in Table 5 of this Permit including but not limited to:

a) Summary reports of stack testing conducted on combustion devices at the facility; and

b) Summary of testing and/or delivery ticket certifications for sulfur content limitations in liquid fuel.

Maintain on a continuous

basis

Facility Wide

Env-A 902.01 (new rule) &

40 CFR 70.6(a)(3)(iii)(

A)

Yes


of 72



Applicable Unit


12. Keep copies of records of VOLs stored for a period of two years. Keep records of tank dimensions and capacity for the life of the tank. Maintain a record of the VOL stored, the period of storage, and the maximum true vapor pressure of that VOL during the respective storage period.

As specified No. 2 Fuel Oil Storage

Tank

40 CFR 60 Subpart Kb,

Section 60.116b(a-c) Yes

13. The owner or operator shall maintain the following records for All Emergency Generators located at the facility:

a) Hours of operation; b) Dates of operation; c ) Monthly and consecutive 12 month

fuel use; and d) Consecutive 12 month hours of

operation.


basis

EU9, EU10, & EU11

Env-A 906

Yes

14. Record and maintain records of the types and amounts of fuel combusted by the Duct Burner each day.


basis

EU8 40 CFR 60 Subpart Dc,

Section 60.48c(g)

Yes

Table 8 below, taken from permit TP-B-0531, lists the recordkeeping requirements for the facility, and any deficiencies noted during the evaluation.

Table 8 – Recordkeeping Requirements

Item # Applicable Requirement Duration/ Frequency

Applicable Unit Rule Citation Compliant

1. Record Retention and Availability: The owner or operator shall keep all records required by this permit on file for a minimum of 5 years.

Keep all records for a minimum

of 5 years

Facility Wide Env-A 902.01(a) Yes

2. The owner or operator shall maintain up-to-date, readily accessible records for the life of the open flares (EU16 and EU17) of the following data as measured during the initial performance test or compliance determination: a. The flare type (i.e., nonassisted), b. All visible emission readings (Table 7,

Item 9), c. Heat content determination (Table 7, Item

3), d. Flow rate or bypass flow rate

measurements (Table 7, Item 19b.), e. Exit velocity determinations (Table 7, Item

4), and

To be maintained for the life of the flares unless

otherwise specified

EU16 EU17

Env-A 906

Yes


of 72




f. Continuous records of the flare pilot flame or flare flame monitoring (Table 7, Item 19a.) and records of all periods of operations during which the pilot flame of the flare flame is absent (Table 8, Item 5).

Records of subsequent tests or monitoring shall be maintained for a minimum of 5 years. Records of the control device vendor specifications shall be maintained until removal.

3. The owner or operator shall maintain readily accessible continuous records of the equipment operating parameters specified in Table 7, Items 19 and 20 as well as up-to-date, readily accessible records for periods of operation during which the parameter boundaries established during the most recent performance test are exceeded.


of 5 years

EU16 EU17 PCE06

Env-A 906

Yes

4. The owner or operator shall keep up-to-date, readily accessible continuous records of the indication of flow to the control device or the indication of bypass flow or records of monthly inspections of car-seals or lock-and-key configurations used to seal bypass lines as specified in Table 7, Item 19.


of 5 years

EU16 EU17

Env-A 906

Yes

5. The owner or operator shall keep up-to-date, readily accessible continuous records of the flame or flare pilot flame monitoring specified in Table 7, Item 19, and up-to-date, readily accessible records of all periods of operation in which the flame or flare pilot flame is absent when the collected gas is routed to the system.


of 5 years

EU16 EU17

Env-A 906

Yes

6. The owner or operator shall keep readily accessible records of all collection and control system exceedences of the operational standard in Table 6, Items 13 and 16.


of 5 years

EU16 EU17

PCE06

Env-A 906 Yes

7. Regulated Toxic Air Pollutants Records: Maintain records documenting compliance with Env-A 1400. Compliance was demonstrated at the time of permit issuance as described in the Division’s Preliminary Determination for application #FY07-0003. The source must update the compliance demonstration using one of the methods provided in Env-A 1405 if: a. There is a revision to the list of RTAPs

lowering the AAL for any RTAP emitted from the Facility;

b. The amount of any RTAP emitted is greater

Maintain Up-to-Date Data


No


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than the amount that was evaluated in the Preliminary Determination;

c. An RTAP that was not evaluated in the Application Review Summary will be emitted; or

d. Stack conditions (e.g. air flow rate) change.

Findings: UNH did not determine, within 90 days following the publication of notice of the revision to Env-A 1400, whether it needed to apply for a permit or modify its existing permit as a result of the latest revision to the AALs in Env-A 1400. A compliance demonstration pursuant to Env-A 1400 was performed on April 26, 2013, and from this demonstration, it was determined that UNH did not need to obtain or modify the permit.

8. General Recordkeeping Requirements for Combustion Devices: The owner or operator of a combustion device shall maintain monthly records of fuel characteristics and utilization, including primary, secondary, tertiary and auxiliary fuels in accordance with the following: a. Fuel consumption; b. Sulfur content as percent sulfur by weight

of fuel or in grains per 100 cubic feet of fuel; and

c. BTU content per cubic foot of fuel. d. Sources operating one or more combustion

devices sharing a common fuel shall record the hours of operation of each combustion device so that the distribution of fuel among each combustion device can be estimated.

e. Items (a) through (d) above must be kept on a daily basis for each day the duct burner (EU08) is operated.

Monthly unless otherwise specified

EU7 EU8


Env-A 903.03

Yes

9. Recordkeeping Requirements for NOx-emitting Generation Sources: Maintain the following records: a. Actual NOx emissions in accordance with

the methods set forth in Env-A 616; b. Fuel usage; c. Hours of operation; d. Power generation as monitored pursuant to

Table 7, Item 14 of this permit; e. Hours of downtime of the power

generation monitoring system, if applicable, during the time period when the generating unit is in operation; and

f. Frequency and results of calibrations performed on the power generation monitoring system, as applicable.

Monthly until January 1, 2014

EU7

EU14

EU15

EU19

Env-A 903.06

Env-A 3706.01(b)

Yes


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10. VOC Emission Statements Recordkeeping Requirements: If the actual annual VOC emissions from all permitted devices located at the Facility are greater than or equal to 10 tpy, then record the following information: a. Identification of each VOC-emitting

process or device, except processes or devices associated exclusively with non-core activities, as defined in Env-A 1204.03(bp);

b. Operating schedule during the high ozone season (June 1 through August 31) for each VOC-emitting process or device identified in (a), above, including: i. Typical hours of operation per day;

and ii. Typical days of operation per calendar

month; c. The following VOC emission data:

i. Actual VOC emissions from each VOC-emitting process or device identified in (a), above for: A. Each calendar year, in tons; and B. A typical high ozone season day

during that calendar year, in pounds per day; and

ii. The emission factors and the origin of the emission factors used to calculate the VOC emissions.



Yes

11. NOx Emission Statements Recordkeeping Requirements: If the actual annual NOx emissions from all permitted devices located at the Facility are greater than or equal to 10 tpy, then record the following information: a. Identification of each fuel burning device; b. Operating schedule during the high ozone

season (June 1 through August 31) for each fuel burning device identified in (a), above, including: 1. Typical hours of operation per day; 2. Typical days of operation per calendar

month; 3. Number of weeks of operation; 4. Type and amount of each fuel burned; 5. Heat input rate in MMBtu/hr; 6. Actual NOx emissions for the

calendar year and a typical high ozone day during that calendar year; and



Yes


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7. Emission factors and the origin of the emission factors used to calculate the NOx emissions.

12. Additional Recordkeeping Requirements: Maintain a 12-month rolling total record of emissions of NOx, SO2, CO, TSP, PM10, and VOC for the purpose of demonstrating that emissions of these pollutants are below the facility wide caps in Table 5 of this permit.

Monthly calculation of

12-month rolling average


Env-A 906

Yes

13. Additional Recordkeeping Requirements: Pollution control equipment Maintain records of all air pollution control equipment activities related to the Thermal Oxidizer (PCE01/EU18) required in Table 7, Items 12 and 13, including: a. The monthly hours of operation; b. Records of thermal oxidizer combustion

temperature monitoring; c. A log of repairs made to the thermal

oxidizer. The log shall include the following: i. The date a problem was observed; ii. The date of the repair; iii. A description of the problem; and iv. The corrective actions taken.

As specified in Table 7b, Items

12 and 13 of this permit

PCE01 EU18

Env-A 906

Yes

14. Additional Recordkeeping Requirements: Pollution control equipment Maintain records of all air pollution control equipment activities related to the Supplemental Utility Flare (EU16/PCE04), Standby Utility Flare (EU17/PCE05) and Preliminary Treatment Unit (PCE06) including: a. Records pertaining to calibration,

maintenance and operation of the heat sensing device on the flares, the gas flow rate measuring device for the flow of landfill gas to the flares and the visual inspection records of any bypass line seal or closure mechanism as required in Table 7, Item 19;

b. Records of operating parameters and monitoring procedures listed in the Monitoring Plan for the Preliminary Treatment Unit required in Table 7, Item 20;

c. Value and length of time for exceedance of applicable parameters monitored under Table 7, Items 19 and 20;

d. Description and duration of all periods when the gas stream is diverted from the

When raw landfill gas is

sent to the applicable

emission units

EU16/PCE04 EU17/PCE05

PCE06

Env-A 906

Yes


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Supplemental Utility Flare (EU16), Standby Utility Flare (EU17) or Preliminary Treatment Unit (PCE06) through a bypass line or the indication of bypass flow as specified in Table 7, Item 19; and

e. Description and duration of all periods when the control device was not operating when landfill gas is present or routed to the control device for a period exceeding 1 hour and length of time the control device was not operating.

Finding: The flares do not have a bypass line.

15. NSPS Startup, Shutdown, Malfunction Records: The owner or operator shall maintain records of the occurrence and duration of any SSM in the operation of the Siemens Combustion Turbine (EU07), Heat Recovery Steam Generator (HRSG) with Duct Burner (DB) (EU08) and Solar Mercury 50 Recuperative Turbine (EU19) or any periods during which a CEMS or monitoring device is inoperative.

For each startup, shutdown,

malfunction or period where

CEMS or monitoring device is

inoperative

EU7 EU8

EU19

40 CFR 60.7 (b)

Yes

16. Startup, Shutdown, Malfunction (SSM) Records: The owner or operator shall maintain records of the occurrence and duration of any SSM in the operation of the Supplemental Utility Flare (EU16/PCE04), Standby Utility Flare (EU17/PCE05) and Preliminary Treatment Unit (PCE06); any malfunction of the air pollution control equipment; or any periods during which a monitoring device is inoperative. In addition: a. When actions taken by the owner or

operator during a startup or shutdown (and the startup or shutdown causes the source to exceed any applicable emission limitation in the relevant emission standards), or malfunction (including actions taken to correct a malfunction) are consistent with the procedures specified in the SSM Plan required in Table 7, Item 21, the owner or operator must keep records

For each startup, shutdown,

malfunction, malfunction of the air pollution

control equipment or period where monitoring device is

inoperative

EU16/PCE04 EU17/PCE05

PCE06

Env-A 906

Yes


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for that event which demonstrate that the procedures specified in the plan were followed. These records may take the form of a “checklist”, or other effective form of recordkeeping and shall contain the following: i. Records of the occurrence and

duration of each SSM of operation and each malfunction of the air pollution control and monitoring equipment; and

ii. Information that confirms conformance with the SSM Plan and describes the actions taken for that event.

b. When actions taken by the owner or operator during a SSM (including an action taken to correct a malfunction) are not consistent with the procedures specified in the SSM Plan required in Table 7, Item 21, and the source exceeds any applicable emission limitation, then the owner or operator must record the actions taken for that event.

c. The owner or operator must maintain the current SSM Plan and make the plan available upon request for inspection and copying. In addition, if the SSM Plan is subsequently revised, the owner or operator must maintain each previous superseded version of the SSM Plan and must make each such previous version available for inspection and copying for a period of 5 years after revision of the plan.

Whenever there is a change in the SSM Plan

Yes


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VIII. Compliance with Reporting Requirements Table 7 below, taken from permit TV-OP-010, lists the reporting requirements for the facility, and any deficiencies noted during the evaluation.

Table 7 – Reporting Requirements

Item # Applicable Requirement Frequency

Applicable Emission

Unit


1. Certification of Accuracy

Any report submitted to the DES and/or EPA shall include the certification of accuracy statement outlined in Section XXI.B of this Permit and shall be signed by the responsible official.

As specified in this Permit

Facility Wide 40 CFR 70.6(c)(1)

Yes

2. NOx Reporting Requirements:

For each combustion device, the owner or operator shall submit to the director, in accordance with the schedule in Env-A 909.02(a), reports of the data required pursuant to Env-A 905.

Annually to DES (no later than April 15th

of the following year)

Facility Wide Env-A 909.03 (eff. 4-23-99) & Temporary

Permit FP-T-0110

Yes

3. In accordance with Env-A 3704.01(b), a NOx-emitting generation source (CT #1) shall not be required to pay NOx emissions reduction fund fees for the first 7 pounds of NOx emitted for each megawatt-hour of electricity produced. In addition, the owner or operator may submit a written request in accordance with Env-A 3703.02 in order to claim exclusion for NOx emissions attributed to heat recovery from these devices. To date, the owner or operator has not submitted a written request.

As stated EU7 Env-A 3704.01(b)


Permit FP-T-0110

Yes

4. The owner or operator shall submit annually to the Division all information pursuant to Env-A 3706.01 (monthly actual NOx emissions and monthly power generation for CT) by April 15th of the following calendar year.

Initially due before April 15, 2007 and

thereafter, annually, by April 15th the

following year

EU7 Env-A 3706.02 (eff. 12-20-01) & Temporary

Permit FP-T-0110

Yes


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Applicable Emission

Unit


5. a) In accordance with Env-A 3707.01(a), in addition to the fees specified in Env-A 700, all applicable NOx-emitting generation sources shall pay to the Division each year, starting in 2006 for NOx emitted in 2005, a NOx emissions reduction fund fee as calculated pursuant to Env-A 3707.03.

b) In accordance with Env-A 3707.02, the owner or operator will submit to the Director with each emission reduction fund fee payment a description of the method used to calculate actual emissions with each emission reduction fee payment.

c) In accordance with Env-A 3707.04, the owner or operator will pay to the Division the NOx emissions reduction fund fee annually, in accordance with the schedule specified in Env-A 705.04 for emission-based fees.

Annually, by April 15th the

following year

EU7 Env-A 3707.01(a),

Env-A 3707.02, Env-A 3707.04 (eff.

12-20-01) & Temporary

Permit FP-T-0110

Yes

6. Permit Deviations

Prompt reporting of deviations from Permit requirements including those attributed to upset conditions as defined in the Permit, the probable cause of such deviations, and any corrective actions or preventative measures taken shall be conducted in accordance with Section XXVIII. of this Permit.

Prompt reporting

(within 24-hours of

discovery of an occurrence)

Facility Wide 40 CFR 70.6(a)(3)(iii)(

B)

Yes


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Applicable Emission

Unit


7. Each owner or operator required to install a continuous monitoring device shall submit excess emissions and monitoring systems performance report (excess emissions are defined in applicable subparts) and-or summary report form (see Item 3 of this Table) to the USEPA and DES semiannually, except when: more frequent reporting is specifically required by an applicable subpart; or the USEPA, on a case-by-case basis, determines that more frequent reporting is necessary to accurately assess the compliance status of the source. All reports shall be postmarked by the 30th day following the end of each six-month period. Written reports of excess emissions shall include the following information:

a) The magnitude of excess emissions computed in accordance with § 60.13(h), any conversion factor(s) used, and the date and time of commencement and completion of each time period of excess emissions. The process operating time during the reporting period.

b) Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected facility. The nature and cause of any malfunction (if known), the corrective action taken or preventative measures adopted.

c) The date and time identifying each period during which the continuous monitoring system was inoperative except for zero and span checks and the nature of the system repairs or adjustments.

d) When no excess emissions have occurred or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.

Semiannually, by January 31st and July 31st

each year

EU7 40 CFR 60 Subpart A

Section 60.7(c)

Yes


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Applicable Emission

Unit


8. The owner or operator of a source subject to 40 CFR 60 which is required to install, calibrate, operate, and maintain a CEM system shall provide the following information in each quarterly emission report specified in Env-A 808.11:

a) The information specified in 40 CFR 60.7(c) and any applicable subpart of 40 CFR 60;

b) The daily averages of gaseous CEM measurements and calculated emission rates; and

c) The information required in Env-A 808.13(a)(5) through (9).

Within 30 days of the end of each calendar

quarter

EU7 Env-A 808.11, 808.12(a)-(c)


Permit FP-T-0110

Yes

9. Annually, on or before April 15th of the following year, submit for each calendar month of the calendar year the consecutive 12 month NOx, SO2, PM10, VOC, CO, and H2SO4 mist emissions totals combined from EU1 through EU10.

Annually, by April 15th the

following year

EU1-EU10 Env-A 910 & Temporary


10. Semi-annual Monitoring, Testing, and Permit Deviations Summary Report

The owner or operator shall submit a summary report of Items #9 and 11 in Table 8a, and permit deviations every 6 months. All instances of deviations from Permit requirements must be clearly identified in such reports. A responsible official must certify all reports consistent with Section XXI.B. of this Permit.

Semi-annually by July 31st and January 31st of each

calendar year.

Facility Wide 40 CFR 70.6(a)(3)(iii)

(A)

Yes

11. Payment of Emission Based Fees

Annual payment of emission based fees shall be conducted in accordance with Section XXIII of this Permit. The owner or operator of a stationary source, an area source, or device having actual emissions of 1,000 tons or less shall pay to the department the annual emission-based fee no later than April 15th each subsequent year for emissions from the previous calendar year.

Annually (no later than April

15th of the following year)

Facility Wide


Permit FP-T-0110

Yes


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Applicable Emission

Unit


12. Annual Emissions Report

The owner or operator shall submit an annual emissions report on or before April 15th of the following year including:

a) The actual calendar year emissions of the stationary source, area source or device and the methods used in calculating such emissions in accordance with Env-A 705.02, Determination of Actual Emissions for Use in Calculating Emission-based Fees; and

b) For combustion devices, all information in accordance with Env-A 903.03, General Record keeping Requirements for Combustion Devices.



Facility Wide Env-A 907.01 (eff. 4-23-99) & Temporary

Permit FP-T-0110

Yes

13. Annual Compliance Certification

Annual compliance certification shall be submitted in accordance with Section XXI of this Permit.



Facility Wide 40 CFR 70.6(c)(1)

Yes

Table 9 below, taken from permit TP-B-0531, lists the reporting requirements for the facility, and any deficiencies noted during the evaluation.

Table 9 - Reporting Requirements

Item # Applicable Requirement Frequency Applicable Emission

Unit


1. Annual Emissions Report: The Owner or Operator shall submit an annual emissions report which shall include the following information: a. Actual calendar year emissions from

each device of NOx, CO, SO2, TSP, and VOCs (speciated by individual VOC), HAPs (speciated by individual HAP), and RTAPs (speciated by individual RTAP);

b. The methods used in calculating such emissions in accordance with Env-A 705.02, Determination of Actual Emissions for Use in Calculating Emission-Based Fees; and

Annually (received by DES no later

than April 15th of the following

year)


Yes


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Unit


c. rdance with Table 8b, Items 8 and 12. All information recorded in acco

2. Acid Deposition Control Program Reporting Requirement: The owner or operator shall submit an annual report by April 15th of the following year containing the information required in Table 8b, Item 8 a., b., and c. This information is also required to be submitted as part of the Annual Emission Report in Table 9b, Item 1 above. Therefore, the report can be streamlined into one report so long as both titles are clearly located on the report.



year)


Yes

3. Reporting Requirements for NOx-Emitting Generation Sources: If the actual annual NOx emissions from the Siemens Alstom Power Combustion Turbine (EU07), Reciprocating Engine #1, (EU14), Reciprocating Engine #2 (EU15) and the Solar Mercury 50 Recuperative Turbine (EU19) are greater than 5 tpy combined, then the owner or operator shall submit all the data collected pursuant to Table 8b, Item 9 with the annual emissions report.


than April 15th of the following year) with the last report due on April 15,

2014

EU7 EU14 EU15 EU19

Env-A 3706.03

Yes

4. Annual VOC Emission Statements Reporting Requirements: If the actual annual VOC emissions from all permitted devices located at the Facility are greater than or equal to 10 tpy, then include the following information with the annual emission report: a. Facility information, including:

i. Source name; ii. Standard Industrial Classification

(SIC) code; iii. North American Industrial

Classification System (NAICS) code;

iv. Physical and mailing addresses; and

b. A breakdown of VOC emissions reported pursuant to Table 9, Item 1 by month; and

c. All data recorded pursuant to Table 8b, Item 10.



year)

Facility Wide

Env-A 908.02

Yes


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Unit


5. Annual NOx Emission Statements Reporting Requirements: If the actual annual NOx emissions from all permitted devices located at the Facility are greater than or equal to 10 tpy, then include the following information with the annual emission report: a. A breakdown of NOx emissions

reported pursuant to Table 9b, Item 1 by month; and

b. All data recorded in accordance with Table 8b, Item 11.



year)

Facility Wide

Env-A 909.02 Env-A 909.03

Yes

6. Prompt Reporting of Permit Deviations: The owner or operator shall promptly report deviations from permit requirements by phone, fax or e-mail in accordance with Section XIX of this permit.

Within 24 hours of discovery of

occurrence

Facility Wide Env-A 911

Yes

7. NSPS – General Provisions: Notification Requirement: The owner or operator shall furnish the USEPA Administrator written notification or, if acceptable to both the Administrator and the owner or operator of a source, electronic notification, as follows: a. A notification of the date construction

(or reconstruction as defined under 40 CFR §60.15) of an affected facility is commenced postmarked no later than 30 days after such date. This requirement shall not apply in the case of mass-produced facilities which are purchased in completed form.

b. A notification of the actual date of initial startup of an affected facility postmarked within 15 days after such date.

c. A notification of any physical or operational change to an existing facility which may increase the emission rate of any air pollutant to which a standard applies, unless that change is specifically exempted under an applicable subpart or in 40 CFR §60.14(e). This notice shall be postmarked 60 days or as soon as practicable before the change is commenced and shall include information describing the precise nature of the change, present and proposed emission control systems,

As specified within

regulation

EU19 40 CFR §60.7(a)

Yes


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Unit


productive capacity of the facility before and after the change, and the expected completion date of the change. The Administrator may request additional relevant information subsequent to this notice.

d. A notification of the date upon which demonstration of the continuous monitoring system performance commences in accordance with 40 CFR §60.13(c). Notification shall be postmarked not less than 30 days prior to such date.

e. The address for USEPA Region 1 is: USEPA New England Attn: Air Compliance Clerk 5 Post Office Square Suite 100 (OES04-2) Boston, MA 02109-3912

8. Semi-annual Landfill Gas Compliance Report: The owner or operator shall submit to DES a semi-annual compliance report of the information required in Table 8b, Items 14 (c), (d) and (e).


each year, with the first report due July 31,

2011

EU16 EU17

PCE06

Env-A 910

Yes

9. Periodic Startup, Shutdown and Malfunction Report: In the event that an SSM event occurs pursuant to Table 8b, Item 16 a., the owner or operator shall report the following information: a. Name, title, and signature of the owner

or operator or other responsible official who is certifying its accuracy;

b. Number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded; and

c. Information required in Table 8b, Item 16 a.


each year

EU16 EU17

PCE06

Env-A 910

Yes

10. Immediate Startup, Shutdown and Malfunction Report: In the event that an SSM event occurs pursuant to Table 8b, Item 16 b., the owner or operator shall report such actions within two (2) working days after commencing actions inconsistent with the SSM Plan, followed by a letter within seven (7)

Within 2 working days notification by phone followed

by a letter within 7

working days

EU16 EU17

PCE06

Env-A 911

Yes


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Unit


working days after the end of the event. The letter shall contain the name, title, and signature of the owner or operator or other responsible official who is certifying its accuracy, explaining the circumstances of the event, the reasons for not following the SSM plan, describing all excess emissions and/or parameter monitoring exceedences which are believed to have occurred (or could have occurred in the case of malfunctions), and actions taken to minimize emissions in conformance with Table 5, Item 18.

IX. Permit Deviation Reporting Requirements During the inspection period, DES identified the following permit deviations: In 2011 there were two deviations reported. During the second quarter of 2011, data availability of the NOx CEMS on turbine #1 (EU07) was 75.1%, which is below the permit requirement of 90% stated in Table 5, Item 14 of permit TV-OP-010. Most of the missing data is attributed to software upgrades. Daily calibration reports indicate the CEMS were operating properly and there were no excess emissions during the period. The second deviation was for an excess NOx emission of 25.6 ppm, which exceeds the NOx emission limit of 25 ppm stated in Table 4b of permit TV-OP-010. In 2012 there were five deviations reported. On July 2, November 2, and December 30, had excess NOx emissions of 22 to 32 ppm, which exceeds the NOx emission limit of 25 ppm stated in Table 4b of permit TV-OP-010. There were two deviations reported for testing issues. In accordance with Table 7, Item 15 of permit TP-B-0531, NOx testing on turbine EU19 is due every two years or in November 2011. The required test in 2011 was not done and was subsequently conducted on March 23, 2012. The second testing issue was when engines EU14 and EU15 were tested on June 27, 2012. CO emissions exceeded the limit of 2.75 gm/bhp-hr stated in Table 5 of permit TP-B-0531. UNH did a cylinder head rebuild and retested on July 19, 2012. Test results indicated the CO emissions were below the permit limits. There have been no permit deviations reported in 2013.


X. Other Findings a) UNH has not reported the annual run hours of each emergency generator in its Annual Emissions Reports. DES recommends that UNH report the annual run hours of each emergency generator to demonstrate compliance with Table 4a, Item 5 of Permit TV-OP-010.

On August 27, 2013, DES received an email from UNH with documentation which demonstrated that UNH is maintaining monthly hour meter readings on each emergency generator. UNH needs to include this data in its Annual Emissions Reports.

XI. Enforcement History and Status During the inspection period, DES has had no enforcement actions against UNH.

XII. Compliance Assistance, Recommendations and Corrective Actions During the on-site inspection, no compliance assistance ensued that would lead to corrective actions completed at that time. Based on the findings of this compliance evaluation, DES recommends the following actions to bring the facility into compliance with the identified deficiencies and future reporting requirements:

a) Report the annual run hours of each emergency generator in its Annual Emissions Report. b) File documentation on the QA/QC Plans no later than April 15th of each year.

c) Submit to DES, within 30 days of completion, the CGA Report for each quarter it was required. d) Conduct NOx RACT testing on the Solar Turbine (EU19) every two years as required. e) UNH needs to determine, within 90 days following the publication of notice of the revision to

Env-A 1400, whether it needs to apply for a permit or modify its existing permit as a result of the latest revision to the AALs in Env-A 1400.

Report Prepared By Alan H. Moulton

Title Compliance Assessment Engineer

Signed

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APPENDIX A

LIST OF ALL EMERGENCY GENERATORS

As of: 8/14/13

Emission Unit ID

Description & Location

Manufacturer Model Serial # kW Fuel Firing Rate

(gal/hr or cf/hr)

Heat Input

(MMBtu/hr)

Date Installed

EG1 Central Heating Plant (Not Dispatch or Black Start)

Caterpillar 3306 66D19216 155 Diesel 12.3 1.7 Pre 2006

EG2 Morse Hall

Caterpillar 3406 2WB03136 250 Diesel 19 2.6 Pre 2006

EG3 Adams Tower West (Formerly New England Center)

Caterpillar 3306DBI 85Z04098 200 Diesel 15.8 2.2 1988

EG4 Water Supply Allis/Chalmers 25000 1-7451-69053

25-03545 200 Diesel 15 2.1 Pre 2006

EG5 Gables Building (Serves Bldgs. A,B,&C)

Caterpillar 3408B 6NB00283 250 Nat Gas 3200 3.2 1998

EG6 Whittemore Center

Caterpillar 3306 2TM00105 250 Diesel 19.4 2.7 1995

EG7 Rudman Hall (Biosciences)

Caterpillar 3412 81Z16491 600 Diesel 46.1 6.3 1994

EG8 See EU09

Black Start Emergency Generator at Central Heating Plant

Caterpillar 3412 BLG02735 750 Diesel 54.8 7.5 2004

EG9 Data Center (At One Leavitt Lane)

Caterpillar 3306 7YR02974 250 Diesel 19.1 2.6 Pre 2006

EG10 Gregg Hall (Formerly ETB)

Caterpillar 3406 4FD02289 150 Nat Gas 734 0.73 2001

EG11 Mills Hall

Caterpillar 3406 CTS00256 240 Nat Gas 2700 2.7 2002

EG12 Holloway Commons Dining Hall

Cummins GTA855G3 25275630 250 Nat Gas 1400 1.4 Dec 2002

EG13 Dispatch (Located in CHP)

KIA SD20 3.0 C2920 20 Diesel 2 0.27 Pre 2006

EG14 Huddleston Hall

White G2300X14 MB3319406 30 Nat Gas 500 0.5 Pre 2006

EG15 Dimond Library

Caterpillar 3208 5YF03487 200 Diesel 15.6 2.1 1998

EG16 Parson Hall 1

Doosan D146L EEZ0G001745 260 Nat Gas 2782.0 2.8 Jun 2011


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Emission Unit ID



(gal/hr or cf/hr)

Heat Input

(MMBtu/hr)

Date Installed

EG17 Print & Mail Services Building (PAMS)

Ford ESG64216005E

03-02-051476 45 Nat Gas 585 0.59 1994

EG18 Stoke Hall

Isuzu 4001E 03421/A1 15 Nat Gas 255 0.26 1997

EG19 Christenson Hall

Ford C5PG-005-A

18039 H60KT 100 Nat Gas 1100.0 1.1 2006

EG20 Coastal Marine Building

Onan Unknown C880107523 30 Diesel 2.6 0.36 Pre 2006

EG21 Field House

Cummins 4BT-3.9 44Z37195 60 Diesel 4.7 0.64 Pre 2006

EG22 Fire Department

Ford LRG 425 04WG25612 25 Nat Gas 450 0.45 2010

EG23 Horton Hall

Onan 15RJC 4XR8 633R 15 Nat Gas 255 0.26 1967

EG24 Jackson Laboratory

Caterpillar 1104C-44T 2442-1800 70.5 Diesel 3.7 0.5

EG25 Kendall Hall Ford C5PF-6005-A

26739-K23KR 30 Nat Gas 600 0.6 Pre 2006

EG26 McConnell Hall

Ford C5PF-6005-A

22822-S2KT 30 Nat Gas 600 0.6 1968

EG27 Mini Dorm Buildings

Ford 2712E 575953909 30 Diesel 2.6 0.36

EG28 Parson Hall 2 Ford C5PG6 005-A

20912-C20KR 45 Nat Gas 585 0.59 Pre 2006

EG29 Philbrook Hall

International V549 112546 85 Nat Gas 1400 1.4

EG30 Telecom Building

Kohler 150 REZG 227090 150 Nat Gas 1930.0 2.0 2010

EG31 Williamson Hall

Ford C5PG-600-A

29268 A-17-HM

45 Nat Gas 585 0.59 1971

EG32 Health Service Building

White No Model # 3333394G3400X357

45 Nat Gas 600 0.6 1988

EG33 Randall Hall

Ford WSG 1068 05QS48626 63.5 Nat Gas 894.0 0.9 Mar 2007

EG34 Aquaculture Lab at Equine Center

Winco PSS 12 H/A 85377 M03 12 Propane 2.2 0.2 Pre 2006

EG35 Cable TV Head End Building

Onan 705JB3N4C 3RV/2835P 7.5 Nat Gas 134.0 0.1 Pre 2006

EG36 New Castle Coastal Marine Lab

Caterpillar C4.4 E5M01130 60 Diesel 5.3 0.7

EG37 New Castle Pier Support Facility

Caterpillar C4.4 E5M00299 100 Diesel 6.5 0.9


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Emission Unit ID



(gal/hr or cf/hr)

Heat Input

(MMBtu/hr)

Date Installed

EG38 Fairchild Hall Olympian G40F3 OLY0000LNGC00922

40 Nat Gas 576.0 0.6 May 2007

EG39 Gables North Cummins WSG 1068 05QS48564 225 hp

Nat Gas 557.0 0.6 Oct 2005

EG40 Gables South Cummins WSG 1068 05RS44735 255 hp

Nat Gas 557.0 0.6 Sep 2005

EG41 Gables Sewer Lift

Cummins WSG 1068 06SS58786 225 hp

Nat Gas 557.0 0.6 Aug 2006

EG42 Hubbard Hall

Onan 705JB 17C 941284 7.5 Nat Gas 134.0 0.1 1967

EG43 James Hall

Caterpillar/GM G150G1 No Serial # 150 Nat Gas 1798.0 1.8 Jun 2009

EG44 Kingsbury Hall

Caterpillar CTP02437 0000JKAP00339

350 Nat Gas 4472.0 4.5 2006

EG45 Ritzman Hall Kubota 95A-038-24S

CD008-A161.0118CDYN

8 Diesel 0.7 0.1 Pre 2006

EG46 SERC A Caterpillar G3406TA CT00548 240 Nat Gas 2894.0 2.9 Sep 2007 EG47 SERC B Caterpillar/GM G125G1 8P1L13989 125 Nat Gas 1508.0 1.5 Sep 2007 EG48 SERC C Caterpillar/GM G150G1 8P1L13452 150 Nat Gas 1798.0 1.8 Sep 2007 EG49 Stillings Hall

Onan JC 2006-0005 7.5 Nat Gas 134.0 0.1

EG50 Chase Ocean Engineering

Generac SG0175-K3613380

88486 175 Nat Gas 2225.0 2.3 May 2008

SERC: Southeast Residental Community


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APPENDIX B

LIST OF INSIGNIFICANT BOILERS AND FURNACES

As of: 8/14/13

Emission Unit ID Description & Location

Maximum Heat Input Rate (MMBtu/hr) &

Fuels Craft Cottage Boiler/Heater 0.20 (Nat Gas) Schofield House Boiler/Heater 0.20 (Nat Gas) Verret House Boiler/Heater 0.20 (Nat Gas) Stoke Building Boiler/Heater 0.20 (Nat Gas) Lockinvar1 Building Boiler/Heater 0.20 (Nat Gas) Lockinvar2 Building Boiler/Heater 0.20 (Nat Gas) Philbrook1 Building Boiler/Heater 0.20 (Nat Gas) Philbrook2 Building Boiler/Heater 0.20 (Nat Gas) Barton/Cote Buildings Boiler/Heater 0.20 (Nat Gas) Greg Hall (Environmental Technology Building)

Boiler/Heater #1 3.57 (Diesel)

Greg Hall (Environmental Technology Building) Boiler/Heater #2

3.57 (Diesel)

Greg Hall (Environmental Technology Building) Boiler/Heater #3

3.57 (Diesel)


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These boilers are in a list submitted to EPA as being subject to 40 CFR 63 Subpart JJJJJJ

Emission Unit ID Emission Unit Name

(design and manufacturer name)

Size: Rated Heat Input Capacity

(MMBtu/hr) Fuels Used

11 Brk Wy Peerless 0.402 #2 oil 1 Leavitt Buderus 0.556 #2oil

Jackson Lab Weil McLain 0.655 #2oil Carp Biasi 0.315 #2oil Hersy Peerless 0.208 #2oil

Equin office Weil McLain 0.152 #2oil Farms Weil McLain 0.814 #2 oil

Personal Weil McLain 0.115 #2oil Kingm farm Weil McLain 0.100 #2oil Woodman Weil McLain 0.100 #2oil

Light Horse Weil McLain 0.100 #2oil VIS Weil McLain 0.150 #2oil Ritz Weil McLain 0.344 #2oil

11 Brk Wy Peerless 0.402 #2oil Grant Weil McLain 0.152 #2oil EHS Weil McLain 0.114 #2oil

Dunlap 74 Weil McLain 0.269 #2oil Janetos Weil McLain 0.115 #2oil

E. Dem 515 Weil McLain 0.184 #2oil EHS Perp Weil McLain 0.114 #2oil

Rice Weil McLain 0.126 #2oil Wolfe 27555 Weil McLain 0.157 #2oil Wolfe 27556 Crown 0.133 #2oil

Kingm offices up Weil McLain 0.158 #2oil LTHRS Weil McLain 0.115 #2oil Mathes Weil McLain 0.100 #2oil

Lib Storage Weil McLain 0.212 #2oil Coastal Weil McLain 0.152 #2oil

Dunlap 37252 Weil McLain 0.126 #2oil Garage Weil McLain 1.904 #2oil

Equin Center Weil McLain 0.100 #2oil Kingm offices down Peerless 0.208 #2oil

E. Dem 514 Weil McLain 0.184 #2oil Woodman Weil McLain 0.171 #2oil

Batch Peerless 0.120 #2oil Saddleback Thermo Pride 0.145 #2oil Horti-GRN2 Royal Oil 0.240 #2oil Horti-GRN1 Royal Oil 0.240 #2oil

8 Spinney Beckett/Bryant 0.119 #2oil Kingm lab Airco/Beckett 0.168 #2oil

Moiles Weil McLain 0.133 #2oil Mariotti Weil McLain 0.210 #2oil

Dairy Bar Boiler Weil-McLain 3.44 #2 oil

the state of new hampshire department of ......ng natural gas nox oxides of nitrogen nsps new source...

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