FERC PDF (Unofficial) 9/29/2014 4:29:38 PM. Title V Permit Modification Addendum Submitted June 23, 2014

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1 Title V Permit Modification Addendum Submitted June 23, 2014

2 REVISED TITLE V PERMIT MODIFICATION APPLICATION Algonquin Gas Transmission, LLC > Stony Point Compressor Station Algonquin Incremental Market (AIM) Project and Algonquin Gas Transmission (AGT) Project Prepared For: Algonquin Gas Transmission, LLC Stony Point Compressor Station Lindberg Road Stony Point, NY Prepared By: TRINITY CONSULTANTS 5 Great Valley Parkway, Suite 322 Malvern, PA (610) June 2014 Project Environmental solutions delivered uncommonly well

3 TABLE OF CONTENTS 1. EXECUTIVE SUMMARY Introduction Benefits of the Proposed Project Air Permitting Summary Application Overview PROJECT OVERVIEW Site/process Description AIM Project Description AGT Project Description PROJECT EMISSIONS QUANTIFICATION Turbine Emissions Turbine Normal Steady State Operation Hourly Emissions Turbine Low Temperature Operation Hourly Emissions Turbine Startup and Shutdown Operation Hourly Emissions Turbine Annual Potential Emissions Emergency Generator Emissions Emergency Generator Emission Factors NO x, CO, and VOC Emergency Generator Emission Factors CH 4 and HAP Emergency Generator Emission Factors PM 10, PM 2.5, and SO Emergency Generator Emission Factors CO 2, N 2 O, and CO 2 e Natural Gas Heater Emissions Heater Emissions Factors NO x, CO, and TOC Heater Emissions Factors VOC, CH 4, and HAPs Heater Emissions Factors PM 10, PM 2.5, and SO Heater Emission Factors CO 2, N 2 O, and CO 2 e Parts Washer Emissions Fugitive Emissions Fugitive Emissions from Piping Components Fugitive Emissions from Gas Releases Fugitive Emissions from Tanks Fugitive Emissions from Truck Loading Total Project Emissions Proposed Compliance Demonstration REGULATORY APPLICABILITY Title V and State Permitting Requirements New Source Review Major NSR Permitting Programs Attainment Status of Rockland County, New York Major Source Status of Stony Point NSR Applicability and Significant Emission Rates Major Source NSR Step 1 Compare PEP to Significant Project Threshold Major Source NSR Step 2 Compare NEI to Significant Net Emission Increase Threshold New Source Performance Standards (NSPS) Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants i

4 CFR Part 60 Subpart KKKK Standards of Performance for Stationary Gas Turbines (After February 18, 2005) CFR Part 60 Subpart GG Standards of Performance for Stationary Gas Turbines CFR Part 60, Subpart JJJJ Standards of Performance for Stationary Spark Ignition Internal Combustion Engines National Emission Standards for Hazardous Air Pollutants (NESHAP) CFR Part 63, Subpart T National Emission Standards for Halogenated Solvent Cleaning CFR Part 63, Subpart HH National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities CFR Part 63, Subpart HHH National Emission Standards for Hazardous Air Pollutants from Natural Gas Transmission and Storage Facilities CFR Part 63, Subpart YYYY National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines CFR Part 63, Subpart ZZZZ National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines CFR Part 63, Subpart DDDDD National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters Additional Applicable State Regulations NYCRR Emissions Testing, Sampling and Analytical Determinations NYCRR Air Pollution Prohibited NYCRR Particulate Emissions NYCRR Opacity NYCRR Reasonably Available Control Technology (RACT) For Major Facilities of Oxides of Nitrogen (NO X ) NYCRR 617 State Environmental Quality Review Dispersion Modeling Requirements Division of Air Resources Policy 1 (DAR 1): Guidelines for the Control of Toxic Ambient Air Contaminants NAAQS Modeling Analysis BACT ANALYSIS BACT Requirements Emissions Limitation Each Air Pollutant Proposed Modification GHG Emission Sources Subject to BACT Simple Cycle Natural Gas Fired Combustion Turbine Ancillary Natural Gas Fired Equipment Process (Methane) Sources Projected Emissions of GHG GHG BACT Assessment Methodology Step 1 Identify Control Technologies Step 2 Eliminate Technically Infeasible Options Step 3 Rank Remaining Control Technologies by Control Effectiveness Step 4 Evaluate Most Effective Controls and Document Results Step 5 Select BACT Combustion Turbines GHG BACT Step 1 Identify All Control Technologies Step 2 Eliminate Technically Infeasible Options Step 3 Rank Remaining Control Options by Effectiveness Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants ii

5 Step 4 Top Down Evaluation of Control Options Step 5 Select BACT Equipment Leaks GHG BACT Step 1 Identify All Control Technologies Step 2 Eliminate Technically Infeasible Options Step 3 Rank Remaining Control Options by Effectiveness Step 4 Top Down Evaluation of Control Options Step 5 Select BACT Process Gas Releases GHG BACT Ancillary Combustion Units GHG BACT APPENDIX A: FACILITY PLOT PLAN APPENDIX B: DETAILED EMISSION CALCULATIONS AND VENDOR SPECS APPENDIX C: NYSDEC AIR PERMIT APPLICATION FORM APPENDIX D: NYSDEC P.E. CERTIFICATION FORM APPENDIX E: NYSDEC LIST OF EXEMPT ACTIVITIES FORM APPENDIX F: NYSDEC METHODS USED TO DETERMINE COMPLIANCE FORM APPENDIX G: EMISSION REDUCTION CREDIT QUANTIFICATION AND USE FORMS APPENDIX H: NAAQS AND DAR-1 MODELING ANALYSES APPENDIX I: ECONOMIC ANALYSIS FOR GHG BACT: LDAR PROGRAM A B C D E F G H I Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants iii

6 LIST OF FIGURES Figure 5 1. CO 2 Potential Injection Location Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants iv

7 LIST OF TABLES Table 2 1: Current Facility wide Potential to Emit 2 1 Table 2 2: Emission Reduction Credits Generated from the AGT Project 2 4 Table 3 1: New Mars 100 Turbines Pre Control Emission Factors Normal Operations 3 5 Table 3 2: Applicable Global Warming Potentials 3 9 Table 3 3: New Mars 100 Turbines Pre Control Emission Factors Low Temperature Operation 3 9 Table 3 4: Solar Mars S Turbine Emission Factors Startup Operation 3 10 Table 3 5: Solar Mars S Pre Control Emission Factors Shutdown Operation 3 11 Table 3 6: Waukesha Emergency Generator Emission Factors 3 13 Table 3 7: Cameron Heaters Emission Factors 3 14 Table 3 8: Project Emission Potential from New and Unmodified Associated Units 3 18 Table 4 1: PSD and NNSR Significant Project and Significant Net Emission Increase Thresholds for Major Sources 4 3 Table 4 2: Step 1 Major Source PSD Applicability 4 4 Table 4 3: Step 1 Major Source NNSR Applicability 4 5 Table 4 4: Step 2 Major Source PSD Applicability 4 6 Table 4 5: Step 2 Major Source NNSR Applicability 4 7 Table 5 1: Summary of Post Project GHG Potential Emissions for New Sources 5 1 Table 5 2: Potential CO 2 Control Strategies for Combustion Turbines 5 5 Table 5 3: Comparison of Turbine Heat Rates and Efficiencies 5 11 Table 5 4: GHG BACT for Turbines 5 14 Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants v

8 1. EXECUTIVE SUMMARY 1.1. INTRODUCTION Algonquin Gas Transmission, LLC ("Algonquin") is proposing to increase the pipeline size and compressor station horsepower along Algonquin s existing mainline from Ramapo, New York to multiple mainline delivery points in Connecticut and Massachusetts and greenfield facilities for lateral transport to West Roxbury, Massachusetts. Collectively, this project is referred to as the Algonquin Incremental Market (AIM) Project. The AIM Project will require the addition of horsepower at five existing compressor stations, including the Stony Point compressor station (Stony Point) in Stony Point, New York, which is the subject of this application. Algonquin has initiated pre filing activities with the Federal Energy Regulatory Commission ( FERC ) which has been issued Docket No. PF Algonquin operates a natural gas compressor station in Stony Point, New York located in Rockland County. As a part of the AIM project, Algonquin is proposing to install the following equipment at Stony Point: Two new Solar Mars 100 natural gas fired turbine driven compressor units; A new Waukesha natural gas fired emergency generator; Two new fuel gas heaters; and A new gas cooler for the new compressor units. The installation of the above equipment will increase the number of piping components at the station which could result in additional fugitive emissions due to equipment leaks. The AIM project will also include several changes at the facility which do not have an impact on emissions. In addition to the AIM project, Algonquin is also proposing to complete a separate project that involves several modifications and environmental improvements to existing equipment at the Stony Point. Collectively, this project is referred to as the Algonquin Gas Transmission (AGT) project. As a part of the AGT project, Algonquin is proposing to make the following changes at Stony Point: Replacement of the existing natural gas fired Solar Mars 90 turbine compressor driver (EU T00007) with a new Mars 100 natural gas fired compressor driver with a lower vendor guaranteed NO X emission rate of 9 ppm; 1 Modifications to existing equipment stacks; Permanent shutdown of an existing 6.3 MMBtu/hr heat input Cleaver Brooks boiler; Permanent shut down of four (4) existing natural gas fired 2,700 hp Clark TLA 8 reciprocating engines; and Installation of a new remote reservoir parts washer. The AGT project will also include several changes at the facility which do not have an impact on emissions. The AGT project will take place concurrently with the AIM project or immediately subsequent to the AIM project. As such, for New York State Department of Environmental Conservation (NYSDEC) air permitting purposes, the AIM and AGT projects constitute a single project and will be referred to collectively as the proposed project in this permit application. 1 NOX emission rate of 9 15% O2 is for steady-state operation at % engine load for all ambient temperatures above 0oF. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 1-1

9 Air emissions from the facility are permitted under Title V Operating Permit Number /0027 (effective May 25, 2010), issued by the NYSDEC BENEFITS OF THE PROPOSED PROJECT The proposed project will provide the Northeast with a unique opportunity to secure a cost effective, domestically produced, environmentally friendly source of energy to support its current demand, as well as its future growth, for clean burning natural gas. The proposed project is an infrastructure investment that expands the pipeline capacity of the existing Algonquin system, which will allow abundant regional natural gas supplies to flow reliably into New England, helping to meet the increasing demand from home heating and electric generation while lowering energy costs. The proposed project will provide up to 342,000 decatherms per day (Dth/d), designed to meet the requirements of customers throughout the region. In addition to reliability and cost benefits, the increased availability of natural gas to the region provides environmental benefits by increasing the supply of a cleaner burning fuel alternative to other traditional fuels such as biomass, coal, and fuel oils. Further, Algonquin has minimized the environmental impacts of the proposed project by proposing to increase horsepower at Stony Point by installing efficient, low emitting Solar Mars 100 natural gas turbine driven compressor units. The three Mars 100 turbines are designed to minimize combustion emissions through the use of state of the art SoLoNOx dry low emissions technology and oxidation catalyst on the turbine. For this project, Solar has guaranteed NO X emissions for the new unit at 9 ppmvd (@ 15% O 2 ) during steady state operation at % engine load for all ambient temperatures above 0 F AIR PERMITTING SUMMARY The proposed project involves the installation of new emission units. As such, Algonquin is submitting an application to modify the existing Title V Operating Permit Number /0027. The new turbines will be subject to 40 CFR 60 Subpart KKKK, New Source Performance Standards for Stationary Gas Turbines as well as the applicable state regulations as outlined in Section 4.5 of this report. The new emergency generator will be subject to 40 CFR 60, Subpart JJJJ, New Source Performance Standards for Stationary Spark Ignition Internal Combustion Engines and 40 CFR 63, Subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. A review of major new source review (NSR) applicability of the proposed project at Stony Point indicates that it will trigger Prevention of Significant Deterioration (PSD) permitting per 6 NYCRR Part 231 for greenhouse gases (CO 2 e) only. The project will not trigger permitting requirements for non attainment areas per 6 NYCRR Part 231. Details of this NSR applicability review are provided in Section 4.2 of this report. Algonquin is submitting the enclosed application for a significant modification to the facility Title V permit in accordance with 6 NYCRR (d) for the new turbines. The new emergency generator, fuel gas heaters, and parts washers installed as part of the proposed project are exempt sources per 6 NYCRR APPLICATION OVERVIEW Algonquin is hereby submitting the enclosed air permit application for the proposed project at Stony Point. As required by NYSDEC air permitting requirements, Algonquin is submitting the following information and attachments with this application: Section 2 Project Overview Section 3 Project Emissions Quantification Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 1-2

10 Section 4 Regulatory Applicability Section 5 Best Available Control Technology Review Appendix A Facility Plot Plan Appendix B Detailed Emission Calculations and Vendor Specifications Appendix C NYSDEC Air Permit Application Form Appendix D NYSDEC P.E. Certification Form Appendix E NYSDEC List of Exempt Activities Form Appendix F NYSDEC Methods Used to Determine Compliance Form Appendix G Emission Reduction Credit Quantification and Use Forms Appendix H NAAQS and DAR 1 Modeling Analyses Appendix I Economic Analysis for GHG BACT: LDAR Program The permit application has been certified by a Professional Engineer (P.E.) licensed in New York State. The P.E. certification can be found in Appendix D. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 1-3

11 2. PROJECT OVERVIEW 2.1. SITE/PROCESS DESCRIPTION The existing Algonquin pipeline transports natural gas from New Jersey through southern New England and into eastern Massachusetts. The gas must be compressed at several compressor stations along the pipeline to ensure efficient transportation and delivery to customers at serviceable pressures. The Stony Point facility is an existing compressor station on the Algonquin pipeline located in Rockland County, New York which is in nonattainment for ozone and fine particulates (PM 2.5 ). 2 Rockland County is in attainment for all other pollutants per 40 CFR Air emissions from the facility are permitted under Title V Permit /00027 (Renewal 2) which became effective on May 25, The current facility wide potential to emit of the Stony Point compressor station is as summarized in the following table: Table 2 1: Current Facility wide Potential to Emit Criteria Pollutant Emissions (tons/yr) PM SO2 3.8 NOX CO VOC CO2e 240,611 Pb negligible Total HAPs 88.8 Based on the potential emissions above, Stony Point is currently a major source with respect to the Title V permitting program established under 6 NYCRR and the major source definition per 6 NYCRR (b)(21). Existing permitted emission units at the Stony Point compressor station include the following: EU R00001 R00004: Four (4) Clark TLA 8 natural gas fired reciprocating engines each with a NEMA rating of 2,700 hp; EU T00008: Two (2) Solar Taurus S natural gas fired turbines each with an ISO rating of 7,700 hp; and EU T00007: One (1) Solar Mars natural gas fired turbine with an ISO rating of 12,600 hp. In addition to the permitted emission units described above, several exempt emission units are located at the Stony Point compressor station. These exempt sources include several natural gas fired heaters and boilers with heat inputs less than 10 million British thermal units per hour (MMBtu/hr) and one natural gas fired emergency generator. 2 The New York North New Jersey Long Island, NY-NJ-CT-PA PM2.5 nonattainment area which included Rockland County was redesignated to attainment by EPA on April 18, However, this area is currently defined as a nonattainment area under 6 NYCRR 200.1(av). NYSDEC issued a proposed rulemaking on May 21, 2014 to update the list of nonattainment areas to remove the PM2.5 nonattainment area. As the rulemaking has not be finalized at the time of the submittal of this application, PM2.5 is treated as a nonattainment pollutant in accordance with conversations with NSYDEC. Whether PM2.5 is treated as an attainment or nonattainment pollutant, it will not trigger NSR permitting requirements. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 2-1

12 2.2. AIM PROJECT DESCRIPTION As a part of the AIM project, Algonquin is proposing to install the following new equipment at Stony Point: Two new Solar Mars ,900 HP (ISO) natural gas fired turbine driven compressor units; One new Waukesha VGF24GL (585 bhp) natural gas fired emergency generator; One new Cameron 0.4 MMBtu/hr heat input natural gas fired fuel gas heater; One new Cameron 0.8 MMBtu/hr heat input natural gas fired fuel gas heater; and A new gas cooler for the new compressor units. The installation of the above equipment will increase the number of piping components at the station which could result in additional fugitive emissions due to equipment leaks. The two new Solar Mars turbine driven compressor units will be used for pipeline natural gas compression. Existing Turbines 05 and 06 at the Stony Point compressor station will not be modified as a result of this project. The new turbines will have a simple cycle design and will utilize an oxidation catalyst to control carbon monoxide (CO), volatile organic compounds (VOC), and organic HAP emissions and dry low NO X (DLN) combustion technology to reduce NO X emissions. The new Waukesha (585 bhp) emergency generator has a four stroke, lean burn, natural gas fired stationary reciprocating internal combustion engine. The proposed emergency generator will be installed to meet sitewide emergency electrical demands as a result of the AIM project and will be operated only during normal testing, maintenance, and emergency situations. Per 6 NYCRR (c)(6), emergency power generating stationary internal combustion engines, as defined in section 200.1(vq) of this Title are exempt sources. As such, this generator is an exempt source. Further, the engine will meet the definition of emergency stationary internal combustion engine per 40 CFR and will comply with the requirements for operating emergency engines in 40 CFR (d). Algonquin is proposing to install two Cameron natural gas fired fuel gas heaters. One heater will have a rated heat input capacity of 0.4 MMBtu/hr, and the other heater will have a rated heat input capacity of 0.8 MMBtu/hr. Per 6 NYCRR (c)(1)(i), stationary combustion installations with a maximum rated heat input capacity less than 10 MMBtu/hr burning fuels other than coal or wood are exempt from permitting. As such, the heaters are exempt sources. Site wide potential fugitive emissions may also increase due to the installation of the new equipment. Typical sources of fugitive emissions from natural gas compressor stations include leaks from piping components (valves, flanges, connectors and open ended lines) as well as potential gas release events. The vast majority of gas release events are associated with startup, shutdown, or maintenance activities. Algonquin has provided fugitive emissions estimates for VOC and greenhouse gas (GHG) emissions. Estimates of fugitive emissions are required to be included in Title V permit applications, per 6 NYCRR (d)(3)(ii). 3 Existing storage tanks and truck loading operations will not be physically modified with the project and potential emissions from these emission sources will not increase as a result of the project. However, there may be associated increases in actual emissions from these sources which are accounted for in the NSR applicability calculations for the project. 3 According to 6 NYCRR (b)(40), the project emission potential (PEP) for existing units at major sources is the difference between baseline actual emissions and project actual emissions. Since an increase may be seen in baseline actuals to projected actuals for these emission source types, they are included in the determination of facility-wide PEP. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 2-2

13 A new gas cooler will be installed for the new compressor units at Stony Point compressor station. The gas cooler is used to reduce the temperature of the natural gas after it is compressed at the station. This cooling operation serves to protect the integrity of the pipeline s coating and increase its transfer efficiency. There are no air emissions associated with the gas cooler itself, however there are potential fugitive emissions associated with additional piping components required for its installation. As such, Algonquin has provided fugitive emissions estimates for VOC and greenhouse gas (GHG) emissions associated with the proposed piping modifications. As a part of the AIM project, Algonquin is proposing to complete several additional changes to the existing equipment that will not have an impact on emissions at the facility. Algonquin plans to restage the existing Unit 6 compressor powered by the Solar Taurus 60 (EU T00008). Restaging involves the replacement of certain internal components on the compressor side of the unit (i.e., the compressor s stators and/or impellers) in order to optimize efficiency around a new set of operating conditions. The restage will enable the operation of the compressor to better match the increased pipeline capacity as a result of the AIM Project. The existing turbine driver will not be uprated as part of the restaging performed at the Southeast station. There will be no physical modifications of the Taurus 70 gas turbine driver and the heat input, power output, and emissions from the unit will not change as a result of the restage. As such, the compressor restaging of the Taurus 70 compressor is not a modification to the Taurus 70 gas turbine. Algonquin is also proposing to replace several existing headers and filter separators at the facility, construct several new buildings, and remove an existing building AGT PROJECT DESCRIPTION As a part of the AGT project, Algonquin is proposing to make the following changes at Stony Point: Replacement of the existing natural gas fired Solar Mars 90 turbine compressor driver (EU T00007) with a new Mars 100 natural gas fired compressor driver with a lower vendor guaranteed NO X emission rate of 9 ppm; 4 Modifications to the existing equipment stacks; Permanent shutdown of an existing 6.3 MMBtu/hr heat input Cleaver Brooks boiler; Permanent shut down of four (4) existing natural gas fired 2,700 hp Clark TLA 8 reciprocating engines; and Installation of a new remote reservoir parts washer, Emission reduction credits (ERCs) will be generated from the permanent shutdown of Turbine 07 and Engines 1 4. Algonquin is submitting ERC applications with this permit application for the quantities shown in Table 2 2 below. 4 NOX emission rate of 9 15% O2 is for steady-state operation at % engine load for all ambient temperatures above 0 F. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 2-3

14 Table 2 2: Emission Reduction Credits Generated from the AGT Project Emission Unit CO2e ERCs (tpy) NO2 ERCs (tpy) CO ERCs (tpy) PM10 ERCs (tpy) PM2.5 ERCs (tpy) SO2 ERCs (tpy) VOC ERCs (tpy) R R R R T , Total 41, Additionally, a new parts washer will be installed at the station. The parts washer will be a remote reservoir cold solvent cleaner, for cleaning equipment parts. Per 6 NYCRR (c)(39)(i), cold cleaning degreasers with an open surface area of 11 square feet or less and an internal volume of 93 gallons or less or, having an organic solvent loss of 3 gallons per day or less are exempt from permitting. The parts washer to be installed at the Stony Point compressor station will meets these criteria and as such, will be an exempt source. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 2-4

15 3. PROJECT EMISSIONS QUANTIFICATION This section provides a summary of the calculation methodology used to estimate potential post project emissions for the turbines, emergency generator, three fuel gas heaters, parts washer, and fugitive sources. Appendix B provides the detailed emission calculations for the project TURBINE EMISSIONS Potential emissions from the proposed new Mars 100 turbine driven compressor units at the Stony Point compressor station will all be identical. Manufacturer specifications for the new turbines can be found in Appendix B. Emissions are estimated for operation during normal steady state operating conditions, operation during low temperature events, and operation during startup and shutdown events as described in the following sections Turbine Normal Steady-State Operation Hourly Emissions Table 3 1 provides a summary of the uncontrolled emission factors used for each pollutant during normal steady state operation. Table 3 1: New Mars 100 Turbines Pre Control Emission Factors Normal Operations Pollutant Emission Factor 1 Source NOX 9 ppmvd at 15% O2 Vendor guaranteed emission rate CO 25 ppmvd at 15% O2 Vendor guaranteed emission rate VOC 25 ppmvd TOC at 15% O lb/mmbtu (HHV) VOC TOC: vendor guaranteed emission rate VOC: Table 3.1 2a of AP 42 CH4 25 ppmvd TOC at 15% O lb/mmbtu (HHV) CH4 TOC: vendor specified emission rate CH4: Table 3.1 2a of AP 42 PM10/PM lb/mmbtu (HHV) Table 3.1 2a of AP 42 SO lb/mmbtu (HHV) Table 3.1 2a of AP 42 CO kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 1 N2O kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 2 Total HAPs 25 ppmvd TOC at 15% O2 Multiple HAP factors TOC: vendor specified emission rate HAPs: Table of AP 42 1 The emission factors provided in this table represent uncontrolled emissions at temperatures above 0 F. The three new Mars 100 turbines are designed to minimize combustion emissions through the use of state ofthe art SoLoNOx dry low emissions technology. For this project, Solar has guaranteed NO X emissions for the units at 9 ppmvd (15% O 2 ) during steady state operation at % engine load for all ambient temperatures above 0 F. Algonquin will be the first customer of Solar s to receive a 9 ppm NO X vendor guarantee for a Solar Mars 100 turbine. The standard guarantee for a Mars 100 turbine is currently at 15 ppm NO X. In order to calculate hourly emissions during normal operation, the emission factors provided in the table above are converted to factors in pounds per million standard cubic feet (lb/mmscf) as described in subsequent sections. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-5

16 Turbine Emission Factors NO X, CO and TOC NO x, CO, and Total Organic Carbon (TOC) emitted by the combustion turbines during normal operation are calculated based on the vendor guaranteed emission rates provided in Table 3 1Table 3 3. Although TOC is not a criteria pollutant, it is used to derive the emission factors for VOC, CH 4 (a greenhouse gas), and organic hazardous air pollutants (HAP). The turbine vendor provides the emissions and operating data listed below at ambient temperatures of 0 F, 20 F, 40 F, 60 F, 80 F and 100 F: Fuel: Lower Heating Value (BTU/scf) Turbine Performance: Net Output Power (hp), Heat Input at LHV (MMBTU/hr), Heat Rate at LHV (BTU/hphr) Exhaust Parameters: Exhaust Temperature ( o F), Water Fraction (%), O 2 Content (%, dry), Molecular Weight (lb/lb mol), Flowrate (lb/hr and acfm) Guaranteed Emission Rates for NO X, CO and TOC 15% O 2 ) Operating and emissions data at other ambient temperatures are estimated by fitting the vendor provided data to a curve that best represents the data and interpolating/extrapolating to the desired temperatures. Since the effectiveness of the emissions control inherent in the turbine s combustor design (e.g., SoLoNO x ) is only guaranteed at temperatures above zero F, the ppm values provided in Table 3 1Table 3 3 do not apply to subzero F operating conditions. Further, the mass emission rates of NO X, CO and TOC at a given load decrease with increasing ambient temperature conditions (i.e., fuel consumption at 100% load is highest at lower ambient temperatures). As such, short term, maximum hourly emission rates are estimated based on operating and emissions data at 0.01 F to provide the most conservative estimate. Annual emissions estimates are based on the annual average ambient conditions at the Stony Point compressor station. As such, for annual emissions estimates, the operating data (turbine performance and exhaust gas parameters) are interpolated to estimate emissions at the average annual ambient temperature at the facility. 5 The emission factor at a given ambient temperature is calculated as illustrated in Equation 3 1 through Equation 3 3: 5 A weighted daily average ambient temperature is used in estimating emissions for the Stony Point compressor station and is based on meteorological information in USEPA s TANKS 4.09d database. To determine ambient temperatures, the three meteorological station in closest proximity to the station are reviewed, and the station with the lowest ambient temperatures is conservatively selected. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-6

17 Equation 3 1:,,, % %. %,. Equation 3 Equation 3 Where: T = ambient temperature Maximum hourly emissions estimated at T = 0.01 F Annual average hourly emissions Turbine Emission Factors VOC, CH 4, and HAPs VOC, CH 4, and HAP emitted by the combustion turbines are calculated using the vendor guaranteed TOC emission rate and AP 42 emission factors, as VOC, CH 4, and HAP are constituents of TOC. The TOC emissions factor in terms of lb/mmscf at a given ambient temperature is calculated as outlined above in Section Standard emission factors for VOC, CH 4, HAP, and TOC from stationary gas turbines are provided in Chapter 3.1 of EPA s Compilation of Air Pollutant Emission Factors (AP 42). Table 3.1 2a of AP 42 (version dated April 2000) provides emission factors of lb VOC per MMBtu, lb CH 4 per MMBtu, and lb TOC per MMBtu from natural gas fired turbines. Table of AP 42 (version dated April 2000) provides emission factors for HAPs emitted from natural gas fired turbines. These HAPs include: 1,3 butadiene Acetaldehyde Acrolein Benzene Ethylbenzene Formaldehyde Naphthalene Polycyclic aromatic hydrocarbons (PAH) Propylene oxide Toluene Xylenes Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-7

18 A total HAP emission factor is calculated as the sum of all individual HAP emission factors. Ratios of VOC, CH 4, and HAP to TOC from the AP 42 factors are applied to the TOC factor derived from vendor information to obtain emission factors for VOC, CH 4, and HAP. For normal operation, the uncontrolled VOC, CH 4, and HAP factors are derived as follows: Equation 3 4:,,,., Turbine Emission Factors PM 10, PM 2.5, and SO 2 As indicated in Table 3 1, particulate matter less than 10 microns in diameter (PM 10 ), particulate matter less than 2.5 microns in diameter (PM 2.5 ), and sulfur dioxide (SO 2 ) emitted by the combustion turbines during normal operation are calculated based on the emission factors listed in Table 3.1 2a of AP 42 (version dated April 2000) for stationary gas turbines. The AP 42 emission factors are converted to lb/mmscf as follows: Equation 3 5:,., It is conservatively assumed that PM = PM 10 = PM 2.5. Attachment B provides a letter from Solar Turbines providing PM 10 and PM 2.5 stack test data supporting the appropriateness of using AP 42 emission factors to estimate emissions for the proposed Mars 100 turbine Turbine Emission Factors CO 2, N 2 O and CO 2 e Emission factors for carbon dioxide (CO 2 ) and nitrous oxides (N 2 O) emitted by the combustion of natural gas are calculated based on the emission factors provided for pipeline natural gas combustion in 40 CFR 98, Subpart C, Tables C 1 and C 2, as follows: Equation 3 6:..,, Equation 3 7:..,. Total greenhouse gas (GHG) emissions in terms of CO 2 equivalents (CO 2 e) are equal to the sum of all individual GHGs emitted by the turbines, accounting for the respective global warming potential of each GHG. The GWPs used to calculate CO 2 e emissions for each pollutant emitted by the Project are contained in Table 3 2. GWPs from EPA s GHG Mandatory Reporting Rule (MRR), listed as EPA GWPs in the table below, are used to calculate GHG emissions for compliance purposes, since the Stony Point compressor station is required to comply with the GHG MRR. The facility is required to report actual GHG emissions under the MRR annually and will use the EPA GWPs to calculate those emissions. GWPs from NYSDEC s regulations, listed as NYSDEC GWPs in the table below, are used to calculated GHG emissions for NSR evaluation purposes. 6 6 NYSDEC requested that the NYSDEC GWPs are used for NSR evaluation purposes during the pre-application meeting on April 1, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-8

19 Table 3 2: Applicable Global Warming Potentials Pollutant 1 EPA GWP 2 NYSDEC GWP 3 CO2 1 1 CH N2O Only those GHGs for which quantifiable emissions increases are expected due to this project are listed. 2 EPA GWPs are based on a 100-year time horizon, as identified in Table A-1 to 40 CFR Part 98, Subpart A as amended on November 29, 2013 to incorporate revised GWPs as published in the Intergovernmental Panel on Climate Change (IPCC) 4th Assessment Report (AR4). 3 NYSDEC GWPs are from 6 NYCRR , Table 9 and are based on GWPs published by the IPCC in AR2 and previously incorporated into 40 CFR 98. As such, the CO 2 e factor is derived as follows: Equation 3 8: Turbine Low Temperature Operation Hourly Emissions At extreme low ambient temperatures (i.e., temperatures below 0 F), lb/hr emissions of NO x, CO, and VOC increase. Low temperature hourly emissions were estimated by extrapolating the vendor provided operating data to an extreme minimum temperature of 20 F, using the vendor estimated emission rates at sub zero temperatures (provided in Table 3 3), and following the calculation methodology outlined in the previous section for normal steady state operation. Table 3 3: New Mars 100 Turbines Pre Control Emission Factors Low Temperature Operation Pollutant Emission Factor from Source 1 Source NOX 42 ppmvd at 15% O2 Vendor provided emission rate CO 100 ppmvd at 15% O2 Vendor provided emission rate TOC 50 ppmvd TOC at 15% O2 Vendor provided emission rate 1 The emission factors provided in this table represent uncontrolled emissions. The same emission rates that are used for normal operation for PM 10, PM 2.5, SO 2, CO 2, and N 2 O are used for low temperature operation. However, it should be noted that the maximum hourly fuel consumption increases during low temperature operation, so hourly mass emissions during low temperature operation are greater than hourly mass emissions during normal operation, even for those pollutants for which the emissions on a lb/mmscf basis are not impacted by low temperature operation Turbine Startup and Shutdown Operation Hourly Emissions Emissions during startups and shutdowns are calculated based on vendor specified transient operation profiles which are used to determine the maximum pound per startup or shutdown event as described in further detail in the following sections. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-9

20 Turbine Startup Operation The startup process for the turbine is estimated to take approximately 9 minutes from the initiation of startup to normal operation (startup sequence ends at approximately 50 percent load for most Solar turbines). This includes 3 minutes of ignition idle operation and 6 minutes of loading/thermal stabilization operation. Table 3 4 provides a summary of the emission factors used for each pollutant during the ignition idle and loading/thermal stabilization phases of each startup event. It is assumed that the oxidation catalyst will not yet have a measurable destruction or removal efficiency (DRE) during startup, as it is designed to meet control specifications only during normal operation. Pollutant Table 3 4: Solar Mars S Turbine Emission Factors Startup Operation Ignition Idle Phase Emission Factor from Source 1 Loading/Thermal Stabilization Phase Emission Factor from Source 1 Source NOX 50 ppmvd at 15% O2 60 ppmvd at 15% O2 Vendor specified emission rate CO 10,000 ppmvd at 15% O2 9,000 ppmvd at 15% O2 Vendor specified emission rate VOC 1,000 ppmvd TOC at 15% O lb/mmbtu (HHV) VOC 900 ppmvd TOC at 15% O lb/mmbtu (HHV) VOC TOC: vendor specified emission rate VOC: Table 3.1 2a of AP 42 CH4 PM10/PM2.5 SO2 CO2 N2O Total HAPs 1,000 ppmvd TOC at 15% O lb/mmbtu (HHV) CH4 Same as normal operation Same as normal operation Same as normal operation Same as normal operation 1,000 ppmvd TOC at 15% O2 Multiple HAP factors 900 ppmvd TOC at 15% O lb/mmbtu (HHV) CH4 900 ppmvd TOC at 15% O2 Multiple HAP factors TOC: vendor specified emission rate CH4: Table 3.1 2a of AP 42 TOC: vendor specified emission rate HAPs: Table of AP 42 1 The emission factors provided in this table represent uncontrolled emissions. The new turbine will be equipped with oxidation catalyst, however it is assumed that the catalyst is not fully operational during startups. All pollutants emitted by the combustion turbines during startup events are calculated based on the same methodology that is used to calculate emissions during normal operation. However, rather than calculate lb/mmscf emission factors, pounds per startup event (lb/event) are calculated for each pollutant based on the fuel consumed during the 3 minute ignition idle phase and during the 6 minue loading/thermal stabilization phase as follows: Equation 3 9: Turbine Shutdown Operation,,, The shutdown process for each turbine is estimated to take approximately 8.5 minutes from normal operation to shutdown for a Mars 100. The shutdown event consists of loading/thermal stabilization operation. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-10

21 Table 3 5 provides a summary of the uncontrolled emission factors used for each pollutant during each shutdown event. It is assumed that the oxidation catalyst will be operational during shutdown. The calculation for shutdowns is similar to that for startups as shown in Equation 3 9 above. Table 3 5: Solar Mars S Pre Control Emission Factors Shutdown Operation Pollutant Loading/Thermal Stabilization Phase Emission Factor from Source 1 Source NOX 60 ppmvd at 15% O2 Vendor specified emission rate CO 9,000 ppmvd at 15% O2 Vendor specified emission rate VOC CH4 PM10/PM2.5 SO2 CO2 N2O Total HAPs 900 ppmvd TOC at 15% O lb/mmbtu (HHV) VOC 900 ppmvd TOC at 15% O lb/mmbtu (HHV) CH4 Same as normal operation Same as normal operation Same as normal operation Same as normal operation 900 ppmvd TOC at 15% O2 Multiple HAP factors TOC: vendor specified emission rate VOC: Table 3.1 2a of AP 42 TOC: vendor specified emission rate CH4: Table 3.1 2a of AP 42 TOC: vendor specified emission rate HAPs: Table of AP 42 1 The emission factors provided in this table represent uncontrolled emissions. The new turbine will be equipped with oxidation catalyst, but the control from the catalyst is not accounted for in the factors above Turbine Annual Potential Emissions The emission factors described in the previous sections are multiplied by the following activity data to estimate annual potential emissions for each Mars 100 turbine: Normal, Steady State Operation: Annual fuel consumption as estimated from vendor provided turbine parameters at the annual average ambient temperature for the Stony Point compressor station. Annual potential to emit (PTE) estimates assume 100% utilization (8,760 hours per year). CO, VOC, and HAP PTE estimates take the control efficiency of the proposed oxidation catalyst into account. Further, since an oxidation catalyst provides more complete conversion of CO to CO 2 (also a regulated pollutant), the controlled portion of the CO emissions is added back to the CO 2 emissions rate. Low Temperature Operation: Fuel consumption during low temperature operation as estimated by extrapolating vendor provided turbine parameters to an ambient temperature of 20 o F. It is conservatively assumed that low temperature operations between 20 o F and 0 o F will account for a total of 19 hours per year. There is no operation considered at 20 o F or below. 7 Startup/Shutdown Operations: The number of startup and shutdown events is conservatively estimated at 312 startup events and 312 shutdown events per year for the turbine. No credit for control by the 7 The 13 hours per year of low temperature operation is conservatively determined based on data extracted from USDOE-NREL s National Solar Radiation Database The number of low temperature hours is determined based on data from the three stations in closest proximity to the station. Low temperature hours as well as distance to station are considered in determining the number of low temperature hours at the station for emission calculation purposes. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-11

22 oxidation catalyst is accounted for in the estimation of startup emissions. However, it is assumed that the oxidation catalyst will be operational during shutdown. For some pollutants, emission rates from the combustion turbine are higher during normal steady state operation than they are during startup and shutdown. However, for other pollutants, emission rates may be higher during startup and shutdown than during normal operation. As such, maximum annual emissions for the turbine are the maximum of potential combinations of normal, startup, shutdown, and low temperature operation as summarized in Equations 3 10 through 3 13 below. Equation 3 10:,, Equation 3 11: Equation 3 12:,, Equation 3 13:,,,,, 3.2. EMERGENCY GENERATOR EMISSIONS Algonquin is proposing to install a new Waukesha (585 bhp) four stroke lean burn natural gas fired emergency generator. Manufacturer specifications for the new generator can be found in Appendix B. The emergency generator will operate for no more than 500 hours/year, and therefore meets the definition of an emergency power generating stationary internal combustion engine under 6 NYCRR 200.1(cq). As previously indicated, the generator is an exempt source per 6 NYCRR (c)(6), however the potential emissions for this new unit are included for NSR applicability purposes. Table 3 6 provides information on the emission factors used to calculate emissions from the emergency generator. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-12

23 Pollutant Table 3 6: Waukesha Emergency Generator Emission Factors Emission Factor from Source Source NOX 2.0 g/bhp hr NSPS Subpart JJJJ CO 4.0 g/bhp hr NSPS Subpart JJJJ VOC 1.0 g/bhp hr VOC (without formaldehyde): NSPS Subpart JJJJ Table of AP 42 CH4 1.0 g VOC/bhp hr 1.25 lb/mmbtu (HHV) VOC: NSPS Subpart JJJJ Table of AP 42 PM10/PM lb/mmbtu (HHV) Table of AP 42 SO lb/mmbtu (HHV) Table of AP 42 CO kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 1 N2O kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 2 Total HAPs 1.0 g VOC/bhp hr Multiple HAP factors VOC: NSPS Subpart JJJJ Table of AP 42 In order to calculate hourly emissions, the emission factors provided in Table 3 6 are converted to factors in lb/mmscf. These converted factors are multiplied by the generator s hourly fuel consumption in scf/hr to obtain hourly emissions. The following sections summarize the methods used to obtain lb/mmscf emission factors for each pollutant emitted from the new emergency generator Emergency Generator Emission Factors NO x, CO, and VOC NO x, CO, and VOC emitted by the emergency generator are calculated based on the emission limits established under NSPS Subpart JJJJ in grams per brake horsepower hour (g/bhp hr) for emergency engines greater than 130 hp installed on and after January 1, The VOC emission limit of 1.0 g/bhp hr in NSPS Subpart JJJJ excludes formaldehyde. 9 A VOC factor inclusive of formaldehyde is calculated using the relative emissions of formaldehyde and VOC provided in Table of AP 42 (version dated July 2000). A VOC factor is calculated as the sum of the factors for all trace organic compounds listed in Table which are VOCs. Formaldehyde emissions are proportional to VOC emissions, because formaldehyde is a constituent of VOC. The VOC factor is adjusted to account for formaldehyde as follows: Equation 3 13:..... Vendor specified power output and fuel consumption for the engine are used to convert the g/bhp hr factors. NO x, CO, and VOC factors are derived as follows: Equation 3 14:,,.,, 8 Per Table 1 to Subpart JJJJ of Part Per footnote d of Table 1 to Subpart JJJJ of Part 60. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-13

24 Emergency Generator Emission Factors CH 4 and HAP CH 4 and HAP emissions are calculated using the VOC emission rate and AP 42 emission factors. Standard emission factors for VOC, CH 4, and HAP from natural gas fired engines are provided in Chapter 3.2 of AP 42. Table (version dated July 2000) provides emission factors for VOC, CH 4, and HAPs from four stroke lean burn natural gas fired engines. Using the same ratio method used to calculate CH 4 and HAP emitted from turbines (detailed in Section ), CH 4 and HAP emitted from engines are ratioed based on the VOC emission rate from NSPS Subpart JJJJ Emergency Generator Emission Factors PM 10, PM 2.5, and SO 2 PM 10 and PM 2.5 emitted by the emergency generator are calculated based on the emission factors listed in Table of AP 42 (version dated July 2000) for natural gas fired engines. PM 10 and PM 2.5 emission factors are calculated as the sum of the filterable and condensable PM emission factors. The SO 2 emission factor utilized is also referenced from Table of AP Emergency Generator Emission Factors CO 2, N 2 O, and CO 2 e CO 2 and N 2 O emitted by the emergency generator are calculated based on the emission factors listed in 40 CFR 98, Subpart C, Tables C 1 and C 2. Equation 3 6 and Equation 3 7 show how factors in lb/mmscf are derived for these pollutants. GHGs emitted from the engine include CO 2, CH 4, and N 2 O. CO 2 e emissions are calculated using the GWPs provided in Table NATURAL GAS HEATER EMISSIONS Algonquin is proposing to install a one 0.4 MMBtu/hr (heat input) Cameron natural gas heater and one 0.8 MMBtu/hr (heat input) Cameron natural gas heater. Table 3 7 provides information on the emission factors used to calculate emissions from the heaters. As previously indicated, the heaters are exempt sources per 6 NYCRR (c)(1)(i), however the potential emissions for these new units are included for NSR applicability purposes. Pollutant Table 3 7: Cameron Heaters Emission Factors Emission Factor from Source Source NOX 80 ppmvd at 3% O2 Vendor specified emission rate CO 200 ppmvd at 3% O2 Vendor specified emission rate TOC 140 ppmvd at 3% O2 Vendor specified emission rate VOC 140 ppmvd TOC at 3% O lb/mmscf TOC: vendor specified emission rate Table of AP 42 CH4 140 ppmvd TOC at 3% O lb/mmscf TOC: vendor specified emission rate Table of AP 42 PM10/PM lb/mmscf Table of AP 42 SO lb/mmscf Table of AP 42 CO kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 1 N2O kg/mmbtu (HHV) 40 CFR 98, Subpart C, Table C 2 Total HAPs 140 ppmvd TOC at 3% O2 Multiple HAP factors TOC: vendor specified emission rate Table of AP 42 Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-14

25 In order to calculate hourly emissions, the emission factors provided in Table 3 7 are converted to units of lb/mmscf. These converted factors are multiplied by the each heater s hourly fuel consumption in scf/hr to obtain hourly emissions. Fuel consumption is calculated from the heat output of the heaters assuming a thermal efficiency of 65% and a natural gas heating value of 1,020 Btu/scf. Annual potential emissions are calculated based on average hourly fuel consumption. Maximum hourly potential emissions are calculated based on maximum hourly fuel consumption, assuming an overload capability of 105%. The following sections summarize the methods used to obtain lb/mmscf emission factors for each pollutant emitted from the new heaters Heater Emissions Factors NO x, CO, and TOC NO x, CO, and TOC emitted by the heaters are calculated based on vendor specified emission rates and vendorspecified fuel consumption for the heaters. NO x, CO, and TOC factors are derived as follows: Equation 3 15:,,, % /, %, Heater Emissions Factors VOC, CH 4, and HAPs VOC, CH 4, and HAP emissions are calculated using the TOC emission rate and AP 42 emission factors. Standard emission factors for TOC, VOC, CH 4, and HAP from natural gas fired heaters are provided in Chapter 1.4 of AP 42. Table (version dated July 1998) provides a CH 4 emission factor for natural gas fired external combustion sources. The TOC and VOC factors used in the calculations differ slightly from the factors provided in Table TOC and VOC factors are calculated as the sum of the factors for all speciated organic compounds listed in Table which are TOCs and VOCs, respectively. Table of AP 42 (version dated July 2000) provides emission factors for the HAPs emitted from natural gas fired external combustion units. Using the same ratio method used to calculate CH 4 and HAP emitted from turbines (detailed in Section ), CH 4, HAP, and VOC emitted from heaters are ratioed based on the vendor specified TOC emission rate Heater Emissions Factors PM 10, PM 2.5, and SO 2 PM 10 and PM 2.5 emitted by the heaters are calculated based on the emission factors listed in Table of AP 42 (version dated July 1998) for natural gas fired external combustion sources. The total PM emission factor of 7.6 lb/mmscf, which includes filterable and condensable particulate, is used. It is assumed that all particulate emitted from natural gas combustion is less than 2.5 microns in diameters, such that PM equals PM 10 and PM 2.5. The SO 2 emission factor of 0.6 lb/mmscf from Table of AP 42 is used directly Heater Emission Factors CO 2, N 2 O, and CO 2 e CO 2 and N 2 O emitted by the heaters are calculated based on the emission factors listed in 40 CFR 98, Subpart C, Tables C 1 and C 2. Equation 3 6 and Equation 3 7 show how factors in lb/mmscf are derived for these pollutants. GHGs emitted from the heaters include CO 2, CH 4, and N 2 O. CO 2 e emissions are calculated using the GWPs provided in Table 3 2: Applicable Global Warming Potentials PARTS WASHER EMISSIONS Algonquin is proposing to install a new remote reservoir parts washer. As previously indicated, the parts washer is an exempt source per 6 NYCRR (c)(39)(i), however the potential emissions for this new unit are included for NSR applicability purposes. Potential emissions from the parts washer are calculated based on Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-15

26 the physical and chemical properties of a worst case representative solvent used in the parts washer and the maximum throughput of the parts washer. In order to conservatively calculate potential emissions, it is assumed that all volatile organic compounds in the solvent are emitted to the atmosphere and that the VOC content is 100 percent. The maximum throughput of the parts washer will be 120 gallons of solvent per year, based on past experience and the addition of a safety factor. A worst case specific gravity is assumed based on typical solvents used at other Algonquin sites. Potential VOC emissions from the parts washer are calculated as follows: Equation 3 16: FUGITIVE EMISSIONS Potential fugitive emissions from piping components and gas releases may increase as a result of the proposed project. Potential emissions from tanks and truck loading will not increase, however, there may be associated increases in actual emissions from these sources. The methodologies used to calculate these potential increases are described in the following sections Fugitive Emissions from Piping Components While the design is not yet final, component counts were estimated based on data from similar sized compressor stations. Potential emissions are calculated from the piping components using emission factors from EPA s Protocol for Equipment Leak Emission Estimates (EPA 453/R ), Table 2 4 which provides leak emission factors for oil and gas production operations. Gas service factors are used for components in natural gas service, light oil service factors are used for components in pipeline liquids service, and heavy oil service factors are used for components in oil service. Since an emission factor is not provided for leaks from pump seals in heavy oil service in Table 2 4, the average SOCMI without ethylene emission factor for pumps in heavy oil service from Table 2 1 is used to estimate emissions. Annual emissions are conservatively calculated assuming that the components are in continuous gas/liquid/oil service as follows: Equation 3 17: #,,., The equation above is used to calculate total fugitive gas emitted from the piping components at the Stony Point compressor station. Emissions of individual VOCs, GHGs, and HAPs are calculated by multiplying the total fugitive gas emissions from piping components in gas, pipeline liquid, and oil service by the weight percent of each pollutant in gas, pipeline liquids, and oil. Gas, pipeline liquid, and oil compositions are engineering estimates based on available worst case data to be conservative Natural gas composition is conservatively estimated based on an extended gas analysis taken from an operation in Thomaston, Texas in November The gas compositions is scaled to be representative of gas at the compressor station, as gas in the region has a lower VOC content than gas in the Thomaston, Texas region. Pipeline liquids composition is based on the Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-16

27 Fugitive Emissions from Gas Releases Gas releases occur with both pipeline operation and station operation. The proposed project may result in increased fugitive emissions from gas releases. The potential volume of gas emitted was conservatively estimated in standard cubic feet per year based on the design data for other compressor stations. Emissions of individual VOCs, GHGs, and HAPs are calculated by multiplying the total fugitive gas emissions from gas releases by the weight percent of each pollutant in the natural gas compressed at the facility Fugitive Emissions from Tanks Existing tanks at the Stony Point compressor station may have associated emissions increases due to the proposed project. The associated tanks will not be physically modified with the project. Flashing losses occur when the pressure of a liquid is decreased or the temperature is increased. At Stony Point, flashing losses occur at pipeline liquids storage tanks and include VOCs, GHGs, and HAPs. Total flashing losses are calculated based on a flash gas rate and a representative flash gas density. The flash gas rate is calculated based on a liquids input rate and a flash factor. 12 Emissions of individual VOCs, GHGs, and HAPs are calculated from total flashing losses using a representative pipeline liquids compositions. Working and breathing losses occur at all tanks at Stony Point, including pipeline liquid tanks, lubricating oil tanks, and oil water separators. Working and breathing losses include VOCs, GHGs, and HAPs and are calculated with EPA s TANKS 4.09d program using maximum potential throughputs for each tank Fugitive Emissions from Truck Loading Existing truck loading operations at the Stony Point compressor station may have associated emissions increases due to the proposed project. The associated truck loading operations will not be physically modified with the project. Fugitive emissions occur during the loading of volatile organic liquids into tanker trucks and include VOCs, GHGs, and HAPs. At Stony Point, pipeline liquids and lubricating oil may be loaded into tanker trucks. Total loading losses are calculated based on calculation methods for submerged filling provided in AP 42 Section 5.2 (version dated January 1995). Emissions of individual VOCs, GHGs, and HAPs are calculated from total loading losses using representative pipeline liquids and lubricating oil compositions TOTAL PROJECT EMISSIONS Table 3 8 presents project emission potential from the new units to be installed as a part of the proposed project. For new units, project emission potential is equal to potentials to emit. 13 For the existing, unmodified units with associated emission increases (i.e., associated units), project emission potential may be calculated composition of residual liquids following flashing, calculated based on a laboratory analysis of flashing from an operation in Atlanta, Texas in April Oil is assumed to be 100 percent VOC and contain no GHGs or HAPs. 11 Natural gas composition is conservatively based on an extended gas analysis taken from an operation in Thomaston, Texas, as described in the previous footnote. 12 The liquids input rate is determined based on operator experience with the incorporation of a safety factor, and the flash factor in standard cubic foot per barrel (scf/bbl) was determined in a laboratory analysis of a gas sample taken from Atlanta, Texas. 13 Per 6 NYCRR (b)(40)(i)(a) Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-17

28 as projected actual emissions minus baseline actual emissions. 14 However, in accordance with 6 NYCRR (b)(41)(ii), project emission potential is conservatively set equal to potential emissions. Detailed emission calculations can be found in Appendix B of this application report. Table 3 8: Project Emission Potential from New and Unmodified Associated Units Unit CO2e 1 NOx (tpy) CO (tpy) PM10/PM2.5 (tpy) SO2 (tpy) VOC (tpy) (tpy) New Units: Turbine 07 67, Turbine 08 67, Turbine 09 67, Emergency Generator Gas Heater Gas Heater Parts Washer 0.4 Piping Component Fugitives Gas Release Fugitives 7, Existing, Unmodified Associated Units: Tanks Truck Loading Project Emission Potential 212, For new source review (NSR) purposes, the CO 2 e emissions presented in the table are calculated using the global warming potentials listed under 6 NYCRR , Table 9, as requested by NYSDEC during the pre-application meeting on April 1, It should be noted that Algonquin requests that CO 2 e emissions be calculated using the global warming potentials listed under 40 CFR Part 98, Table A-1 for compliance purposes PROPOSED COMPLIANCE DEMONSTRATION As indicated in Table 3 1, the maximum emission rate for the three new turbines during normal operation will be 9 ppmvd of NO X at 15 percent O 2, on a 3 hour average (consistent with a Method 7 performance test). Algonquin will be the first customer of Solar s to receive a 9 ppmvd NO X vendor guarantee for a Solar Mars 100 turbine. Other Mars 100 units have been guaranteed at 15 ppmvd NO X at 15 percent O 2. Because this is new technology and the resulting NO X emissions are dependent on site specific factors, Algonquin and Solar are requesting the full shakedown period of six months as allowed 6 NYCRR (a) to fully evaluate and tune the new turbine installation to achieve the very low NO X emission rate. 15 Based on information from the vendor, Algonquin anticipates the potential for up to a 6 month shakedown period (i.e., period during which the turbine 14 Per 6 NYCRR (b)(40)(i)(c) 15 Per 6 NYCRR (a), the shakedown period for new or modified emission sources at an existing facility shall not exceed 180 days from the date of commencement of operation. The commencement of operation is define under 6 NYCRR (b)(12) as the date that a proposed new or modified facility first emits or increases emissions of any regulated NSR contaminant to which this Part applies or the date on which the facility shakedown period ends for a proposed modified facility which utilizes future ERCs for netting. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-18

29 manufacturer and owner verifies that the performance guarantees are met) before the 9 ppmvd technology will be completely installed and fully operational on the turbine. The two existing turbines at the Stony Point compressor station which are currently subject to NSPS Subpart KKKK are required to conduct annual stack tests. Per 40 CFR (a), the testing frequency of subsequent performance tests may be reduced to once every two years if the NO x emission results are less than or equal to 75% of the NSPS KKKK emission limit for the turbine. Algonquin proposes to demonstrate compliance with the 9 ppmvd NO x limit for the three new turbines via initial and subsequent emissions testing, in accordance with the compliance demonstration requirements of NSPS KKKK. Prior to the initial compliance demonstration, Algonquin will conservatively estimate emissions from the new turbines based on an emission factor of 15 ppmvd during the shakedown period. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 3-19

30 4. REGULATORY APPLICABILITY This section of the application report addresses the conformity of the proposed project to the applicable permitting programs and air quality regulations 4.1. TITLE V AND STATE PERMITTING REQUIREMENTS 6 NYCRR 201 outlines the NYSDEC s permitting and registration requirements. As the Stony Point compressor station currently operates under a Title V permit, the proposed modifications must be permitted through a modification to the facility s existing Title V permit under 6 NYCRR The proposed project is considered to be a significant modification to an existing major source. As previously discussed, several of the emission units proposed to be installed at the Stony Point compressor station are exempt sources. According to 6 NYCRR (c), exempt activities must be listed in the Title V permit application. The new emergency generator, three new fuel gas heaters, and new parts washer are exempt sources as shown in Appendix E NEW SOURCE REVIEW The federal New Source Review (NSR) program is comprised of two distinct pre construction permitting programs: 1) PSD (for attainment areas/pollutants); and 2) nonattainment New Source Review (NNSR) (for nonattainment areas/pollutants). New York has its own SIP approved programs for PSD and NNSR codified in 6 NYCRR Part 231. The PSD and NNSR applicability presented in this section rely on definitions from 6 NYCRR and tables from 6 NYCRR Major NSR Permitting Programs PSD permitting may apply to facilities located in areas designated as in attainment with the National Ambient Air Quality Standards (NAAQS). Projects that are either new major stationary sources or modifications to existing major sources resulting in a significant emissions increase AND a significant net emissions increase of an attainment pollutant are subject to the PSD permitting program. NYSDEC s PSD permitting program for existing major facilities is established in 6 NYCRR NNSR permitting may apply to facilities located in areas that are designated as not in attainment with the NAAQS for a specific criteria pollutant. Projects that are either new major stationary sources or modifications to existing major sources resulting in a significant net emissions increase of a nonattainment pollutant are regulated under the NNSR program in New York as established in 6 NYCRR for existing major facilities Attainment Status of Rockland County, New York The Stony Point compressor station is located in Rockland County, New York which is classified as in severe nonattainment for the hour ozone NAAQS. Rockland County is currently classified as nonattainment for the 1997 fine particulate matter standard (PM 2.5 ). The New York North New Jersey Long Island, NY NJ CT PA PM 2.5 nonattainment area which included Rockland County was redesignated to attainment by EPA on April 18, However, this area is currently defined as a nonattainment area under 6 NYCRR 200.1(av). NYSDEC issued a proposed rulemaking on May 21, 2014 to update the list of nonattainment areas to remove the PM 2.5 nonattainment area. As the rulemaking has Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-1

31 not be finalized at the time of the submittal of this application, PM 2.5 is treated as a nonattainment pollutant, in accordance with conversations with NYSDEC. Whether PM 2.5 is treated as an attainment or nonattainment pollutant, it will not trigger NSR permitting requirements. For other regulated NSR pollutants, this location is considered an attainment area Major Source Status of Stony Point Major thresholds for PSD regulated pollutant for facilities in New York are established in 6 NYCRR , Table 5. According to 6 NYCRR (b)(21)(v), a 100 tpy major source threshold for criteria pollutants applies to facilities on the list of sources categories in 6 NYCRR (b)(21)(iii)(a) through (z)). Natural gas compressor stations are not one of the source categories identified. Therefore, according to Table 5, the Stony Point compressor station is subject to a 250 tpy threshold for classification as a PSD major source. 16 In addition, a major source threshold of 100,000 applies to greenhouse gases measured as CO 2 e. As indicated in Table 2 1, the Stony Point compressor station is an existing major source with respect to the PSD program. Major facility thresholds for the NNSR regulated pollutants for facilities in New York are established in 6 NYCRR , Table 1 and Table 2. The major facility thresholds for NO x and VOC are both 25 tpy in severe nonattainment areas. The major facility threshold for particulate matter less than 2.5 microns in diameters (PM 2.5 ) is 100 tpy in non attainment areas. As indicated in Table 2.1, the Stony Point compressor station is an existing major source with respect to the NNSR program NSR Applicability and Significant Emission Rates If an existing major source proposes to undergo a physical or operational change, the applicant must review the project emission potential (PEP) associated with the proposed project to determine if the project is considered an NSR major modification. The PEP is compared to the significant project threshold (SPT). If the PEP is less than the SPT, the pollutant does not trigger NSR. If the PEP exceeds the SPT, then the net emissions increase (NEI) must be determined and compared to the significant net emission increase threshold (SNEIT). The NEI takes into account not only emissions increases from the proposed project, but also contemporaneous creditable emission increases at the facility for which an emission offset was not obtained; and any ERC at the facility, or portion thereof, selected by the applicant which is contemporaneous to the project. If the PEP exceeds the SPT and the NEI exceeds the SNEIT for any regulated air pollutant, then PSD and/or NNSR permitting is required. That is, the permit application requirements for PSD and NNSR only apply to those pollutants that result in a significant project increase and a significant net emissions increase. Table 4 1 identifies the significant project threshold and the significant net emission increase threshold for each regulated pollutant as applicable to Stony Point. 16 The PSD source categories are consistent with those established in the federal regulations under 40 CFR 52.21(b)(1)(i)(a). Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-2

32 Table 4 1: PSD and NNSR Significant Project and Significant Net Emission Increase Thresholds for Major Sources Pollutant Significant Project Threshold (Tons/Year) Significant Net Emission Increase Threshold (Tons/Year) Regulated Under PSD or NNSR for Stony Point Compressor Station? Reference 6 NYCRR Carbon Monoxide PSD Table 6 Nitrogen Oxides (as an ozone precursor) NNSR Table 3 Nitrogen Oxides (as a PM2.5 precursor) NNSR Table 4 Nitrogen Dioxide (NO2 National Ambient Air Quality PSD Table 6 Standard) Sulfur Dioxide (SO2 National Ambient Air PSD Table 6 Quality Standard) Sulfur Dioxide (as an ozone precursor) NNSR Table 4 Particulate Matter PSD Table 6 PM PSD Table 6 PM NNSR Table 4 Volatile Organic Compounds NNSR Table 3 CO2e 1 75,000 75,000 PSD Table 6 Lead (elemental) PSD Table 6 1 Any increase in GHG pollutants on a mass basis and 75,000 tpy measured as CO2 equivalents Major Source NSR Step 1 Compare PEP to Significant Project Threshold In the first step of major source NSR applicability, the PEP of PSD and NNSR regulated pollutants from the new emissions units and any other plant wide emissions increases that may occur as a direct result of the proposed project are determined and compared to the significant project threshold. PSD applicability is determined following the procedures outlined in 6 NYCRR 231 8, Modifications to Existing Major Facilities in Attainment Areas (Prevention of Significant Deterioration). Similarly, NNSR applicability is determined following the procedures outlined in 6 NYCRR 231 6, Modifications to Existing Major Facilities in Nonattainment Areas and Attainment Areas of the State within the Ozone Transport Region. Project Emission Potential (PEP) is defined under 6 NYCRR (b)(40) and must consider only the proposed emission increase. According to 6 NYCRR (b)(40), for each regulated NSR contaminant, the PEP is calculated as the sum of the following: For new emission sources, the potential to emit (PTE) of each emission source. For existing emission sources at a major facility, the difference between the baseline actual emissions (BAE) and the projected actual emissions (PAE) of the emission source. Algonquin has elected to use PTE in place of PAE for existing sources as allowed under 6 NYCRR (b)(41)(ii). Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-3

33 For the proposed project, emissions increases have been quantified as outlined in Section 3 and summarized in Table Major Source Step 1 PSD and NNSR Emission Comparison As shown in Table 4 2, without considering contemporaneous changes (i.e., Step 1 emission increase analysis), the PEP is demonstrated to be less than the significant project thresholds for all PSD pollutants except for CO 2 e and NO x. Table 4 2: Step 1 Major Source PSD Applicability Pollutant Project Emits Pollutant? PEP (tpy) Significant Project Threshold (tpy) PEP > Significant Project Threshold? PM Yes No PM10 Yes No SO2 (NAAQS) Yes No NO2 (NAAQS) Yes Yes CO Yes No Pb No 0.6 No CO2e 1 Yes 212,442 75,000 Yes 1 The CO2e emissions presented in the table are calculated using the global warming potentials listed under 6 NYCRR , Table 9, as requested by NYSDEC during the pre-application meeting on April 1, As shown in Table 4 3, without considering contemporaneous changes (i.e., Step 1 emission increase analysis), the PEP was demonstrated to be less than the significant project threshold for SO 2 as a PM 2.5 precursor. For all other NNSR pollutants, PEP exceeds the significance project threshold therefore triggering netting as discussed in the next section. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-4

34 Table 4 3: Step 1 Major Source NNSR Applicability Pollutant Project Emits Pollutant? PEP (tpy) Significant Project Threshold (tpy) PEP > Significant Project Threshold? VOC Yes Yes NOx (as O3 Prec.) Yes Yes PM2.5 Yes Yes SO2 (as PM2.5 Prec.) Yes No NOx (as PM2.5 Prec.) Yes Yes Major Source NSR Step 2 Compare NEI to Significant Net Emission Increase Threshold In the second step of major source NSR applicability, NEI is compared to the SNEIT for any pollutants for which PEP exceeds the significant project threshold. NEI is defined under 6 NYCRR (b)(30) as the aggregate increase in emissions of a regulated NSR contaminant in tpy at an existing major facility resulting from the sum of: The project emission potential of the modification; Every creditable emission increase at the facility which is contemporaneous and for which an emission offset was not obtained; and Any emission reduction credit (ERC) at the facility, or portion thereof, selected by the applicant which is contemporaneous and which was not previously used as part of an emission offset, an internal offset, or relied upon in the issuance of a permit under this Part. Creditable emission increases must be included in the NEI calculation if they are contemporaneous. For pollutants other than NO x and VOC, contemporaneous is defined under 6 NYCRR (b)(13) as the period beginning five years prior to the scheduled commence construction date of the new or modified emission source, and ending with the scheduled commence operation date. Since the Stony Point compressor station is located in a severe ozone nonattainment area, the contemporaneous period is different for NO x and VOC. For these pollutants, the contemporaneous period consists of the five consecutive calendar year period which ends with the calendar year that the proposed modification is scheduled to commence operation. The scheduled commence construction date for the proposed project at the Stony Point compressor station is March The contemporaneous period for pollutants other than NO x and VOC is March 2011 to March The contemporaneous period for NO x and VOC is 2011 to No projects occurred at the facility which resulted in creditable emission increases during the contemporaneous periods. As such, no creditable emission increases are included in the calculation of NEI for the project Emission Reduction Credit (ERC) The Stony Point compressor station is applying for certification of NNSR and PSD ERCs created as a result of the proposed shutdown of Turbine 07 and the four existing reciprocating engines at the facility contemporaneous with this project. The ERCs are calculated in accordance with 6 NYCRR This regulation requires that an ERC may be obtained for any decrease in emissions of a regulated NSR contaminant which is: Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-5

35 Surplus, quantified, permanent, enforceable, and included in a Part 201 permit; Will result or resulted from a physical change in, or change in the method of operation of an emission source subject to Part 201 of this Title that is quantified as the difference between baseline actual emissions and the subsequent potential to emit and is approved in accordance with the provisions of this Part Quantification of ERCs generated by the proposed project is summarized in Table 2 2. The NNSR and PSD ERC Quantification Forms can be found in Appendix G. Under NNSR, Algonquin proposes to use NO x VOC, and PM 2.5 ERCs generated by the project to net out of NNSR. Under PSD, Algonquin proposes to use NO x ERCs generated by the project to net out of PSD. The Use of Emission Reduction Credits (ERC) Form can be found in Appendix G. The ERCs are used in the netting analysis as documented in Appendix B. The CO 2 e, CO, SO 2, and PM 10 ERCs generated by the proposed project will be banked as they are not used in the netting analysis conducted for the project Major Source Step 2 PSD and NNSR Emission Comparison Table 4 4 includes a comparison of NEI to the PSD significant net emission increase threshold for CO 2 e and NO 2, since the PEP exceeds the PSD significant project threshold for these pollutants. The results of this netting analysis show that the proposed project at the Stony Point compressor station is subject to the major source PSD permitting program for CO 2 e only. The PSD dispersion modeling requirements of 6 NYCRR do not apply to CO 2 e. 17 The PSD BACT analysis required under 6 NYCRR for CO 2 e is included in Section 5 of this report. The PSD permit application contents outlined in 6 NYCRR are included in this permit application. Pollutant Table 4 4: Step 2 Major Source PSD Applicability NEI (tpy) Significant Net Emission Increase Threshold (tpy) NEI > Significant Net Emission Increase Threshold? CO2e 1 212,442 75,000 Yes NO No 1 The CO 2 e emissions presented in the table are calculated using the global warming potentials listed under 6 NYCRR , Table 9, as requested by NYSDEC during the pre-application meeting on April 1, The NO 2 NEI includes the use of 18.2 tpy NO 2 ERCs. Table 4 5 includes a comparison of NEI to the NNSR significant net emission increase thresholds for NO x (as an ozone precursor), PM 2.5, NO x (as a PM 2.5 precursor), and VOC, since these pollutants are subject to the NNSR permitting program and PEPs exceeds the NNSR significant project thresholds. Based on the results of this 17 Per 6 NYCRR (c), under the PSD program, the owner or operator of a proposed new or modified facility must demonstrate that allowable emission increase from the proposed facility or modification, in conjunction with all other applicable emission increases or reductions (including secondary emissions) would not, at a minimum, cause or contribute to air pollution in violation of: (1) any national ambient air quality standard in any air quality region; (2) quantified air quality related values (AQRVs) including visibility for the applicable Federal class I areas; and (3) any applicable maximum allowable PSD increment increase over the baseline concentration in any area. National ambient air quality standards, AQRVs, and PSD increments do not exists for CO 2 e. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-6

36 netting analysis, the proposed project at the Stony Point compressor station is not subject to the major source NNSR permitting program. Table 4 5: Step 2 Major Source NNSR Applicability Pollutant NEI (tpy) Significant Net Emission Increase Threshold (tpy) NEI > Significant Net Emission Increase Threshold? VOC No NOx (as O3 Prec.) No PM No NOx (as PM2.5 Prec.) No 1 The VOC NEI includes the use of 2.2 tpy VOC ERCs. 2 The NOx NEI includes the use of 33.2 tpy NOx ERCs. 3 The PM2.5 NEI includes the use of 1.5 tpy PM2.5 ERCs NEW SOURCE PERFORMANCE STANDARDS (NSPS) This section summarizes the applicability of NSPS regulations codified in 40 CFR Part 60 to the new turbine CFR Part 60 Subpart KKKK Standards of Performance for Stationary Gas Turbines (After February 18, 2005) Applicability Pursuant to 40 CFR (a), the three new Solar Mars 100 gas turbines are subject to requirements of 40 CFR 60 Subpart KKKK, because their heat input at peak load will be greater than or equal to 10 MMBtu/hr (HHV) and Algonquin will have commenced the construction or modification of the turbines after February 18, Emission Limits Pursuant to 40 CFR (a) and Table 1 to Subpart KKKK of Part 60 Nitrogen Oxide Emission Limits for New Stationary Combustion Turbines, the three new gas turbines, which will have HHV heat inputs of between 50 and 850 MMBtu/hr, will comply with a NO X emission standard of 25 ppm at 15 percent O 2 or 1.2 lb/mwh useful output as indicated by the vendor guarantee listed in Table 3 1. Subpart KKKK also includes a NO x limit of 150 ppmvd at 15% O2 or 8.7 lb/mwh for turbine operation at temperatures less than 0 F and turbine operation at loads less than 75 % of peak load which the new turbine will meet as indicated by the vendor guarantee listed in Table 3 1. The new turbines will comply with an SO 2 emission standard of 0.9 lb/mw hr gross output and will not burn any fuel that has the potential to emit in excess of lb/mmbtu SO 2 heat input, pursuant to 40 CFR (a)(1) and (2), respectively. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-7

37 General Compliance Requirements Pursuant to 40 CFR (a), the three new turbines, their air pollution control equipment, and their monitoring equipment will be maintained in a manner that is consistent with good air pollution control practices for minimizing emissions. This requirement applies at all times including during startup, shutdown, and malfunction. NO X Monitoring Pursuant to 40 CFR (a), since the three new turbines will not use water or steam injection to control NO X emissions, Algonquin will perform annual performance tests in accordance with 40 CFR to demonstrate continuous compliance. If the NO X emission result from the performance test is less than or equal to 75 percent of the NO X emission limit for a turbine (< ppm at 15% O 2 or < 0.9 lb/mw hr), Algonquin 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% of the NO X emission limit, the Stony Point compressor station will be required to resume annual performance testing. Per 40 CFR 60.8(a), the initial NO X performance tests for the new turbines are required to be conducted within 60 days after achieving the maximum production rate (i.e. the turbine s maximum rated heat output), but no later than 180 days after initial startup. SO 2 Monitoring Pursuant to 40 CFR (a), in order to demonstrate continuous compliance with the applicable lb/mmbtu potential SO 2 emissions limit, the Stony Point compressor station will utilize a current, valid purchase contract, tariff sheet or transportation contract for natural gas that will specify that the maximum total sulfur content of the natural gas used at the facility is less than 20 grains per 100 standard cubic feet. Reporting Pursuant to 40 CFR (b), since the Stony Point compressor station will be conducting annual performance testing in accordance with 40 CFR (a), a written report of the results of each performance test will be submitted to NYSDEC and the USEPA before the close of business on the 60th day following the completion of the performance test. Per 40 CFR 60.7(a)(1), the Stony Point compressor station will submit of notification of the date construction of the each new turbine commenced. The submittals will be postmarked by no later than 30 days after the commencement of construction dates. Per 40 CFR 60.7(a)(3), the submittal of the notifications of the actual dates of initial startup of the new turbines will be postmarked by no later than 15 days after the initial startup dates CFR Part 60 Subpart GG Standards of Performance for Stationary Gas Turbines Pursuant to 40 CFR (b) under 40 CFR Part 60 Subpart KKKK, stationary combustion turbines regulated under Subpart KKKK are exempt from the requirements of Subpart GG. Since the three new turbines at the Stony Point compressor station are subject to 40 CFR 60 Subpart KKKK, they are exempt from 40 CFR 60 Subpart GG. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-8

38 CFR Part 60, Subpart JJJJ Standards of Performance for Stationary Spark Ignition Internal Combustion Engines The new 585 bhp emergency engine will be subject to NSPS Subpart JJJJ since the engine is a lean burn stationary spark ignition internal combustion engine greater than or equal to 500 hp but less than 1,350 hp that was constructed after June 12, 2006 and manufactured after January 1, Emission limits for emergency engines greater than 130 hp are established under Table 1 of NSPS Subpart JJJJ. These emission standards include 2.0 g/hp hr NO x, 4.0 g/hp hr CO, and 1.0 g/hp hr VOC (excluding formaldehyde). In accordance with 40 CFR (b)(2), Algonquin will purchase a non certified engine and demonstrate compliance with the emission limitations. Algonquin will keep a maintenance plan and records of conducted maintenance, and will, to the extent practicable, maintain and operate the engine in a manner consistent with good air pollutant control practice for minimizing emissions, per 40 CFR (b)(2)(ii). In addition, Algonquin will conduct an initial performance test and conduct subsequent performance testing in accordance with 40 CFR every 8,760 hours or 3 years, whichever comes first, thereafter to demonstrate compliance. As the engine is an emergency engine, Algonquin will not operate the engine for more than 100 hours per year for non emergency purposes, according to 40 CFR (d). Algonquin will install a non resettable hour meter as required under 40 CFR (a). Algonquin will submit the initial notification required under 40 CFR (c) and will comply with the recordkeeping requirements under 40 CFR (a) NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP) This section summarizes the applicability of National Emission Standards for Hazardous Air Pollutants (NESHAP) codified in 40 CFR Parts 61 and CFR Part 63, Subpart T National Emission Standards for Halogenated Solvent Cleaning Subpart T is applicable to major sources of HAP at facilities using halogenated solvent cleaners. The parts washer will not use solvent cleaners containing halogens. Therefore, Subpart T is not applicable CFR Part 63, Subpart HH - National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities Per (a) and (b), for major sources of HAP, Subpart HH applies to facilities that process, upgrade, or store hydrocarbon liquids. The natural gas production facility to which the rule applies ends at the point that the natural gas enters a facility in the natural gas transmission and storage category per (a)(3). The Stony Point compressor station is considered a natural gas transmission and storage facility; therefore, Subpart HH does not apply. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-9

39 CFR Part 63, Subpart HHH National Emission Standards for Hazardous Air Pollutants from Natural Gas Transmission and Storage Facilities Per (a) and (b), Subpart HHH applies to glycol dehydration units at major sources of HAP. Since Algonquin will not be constructing any glycol dehydration units as a part of the proposed project, this regulation does not apply to the project CFR Part 63, Subpart YYYY National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines The three new Solar Mars 100 gas turbines will be located at a major source of HAPs. As such, they are subject to 40 CFR 63 Subpart YYYY. Per 40 CFR (b)(4), existing turbines in all subcategories do not have to meet the requirements of Subpart YYYY and of Subpart A and, per 40 CFR (d), the requirements for new turbines which use lean premix combustion have been stayed. EPA has proposed to delete this subcategory from the source category list. The proposed Solar Mars 100 turbines will utilize SoLoNO x which is a lean premix technology and will be subject to the stay of requirements. Algonquin will submit the Initial Notification as required by the rule, but is not subject to any other requirement under Subpart YYYY until EPA takes final action to require compliance CFR Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines The new 585 bhp emergency engine will be subject to NESHAP Subpart ZZZZ, commonly referred to as the reciprocating internal combustion engine (RICE) maximum achievable control technology (MACT). Per 40 CFR (a)(2)(i), the emergency engine is a new stationary RICE located at a major source of HAP. According to 40 CFR (b)(1)(i), a new emergency stationary RICE with a site rating of more than 500 bhp at a major source does not have to meet the requirements of Subpart ZZZZ or Subpart A, except for the initial notification requirements of 40 CFR (f). As such, Algonquin will submit the Initial Notification as required by the rule for the new emergency engine CFR Part 63, Subpart DDDDD - National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters Applicability The new fuel gas heaters will be used to maintain the temperature of the fuel gas for the new turbines; therefore, the heaters are considered process heaters per 40 CFR and are subject to Subpart DDDDD per 40 CFR Since the process heaters will be constructed after June 4, 2010, they are new units under the rule. Additionally, the process heaters will burn natural gas; therefore, they will be considered a Gas 1 units. Requirements Since the process heaters are less than 5 MMBtu/hr, Subpart DDDDD requires tune ups to be conducted once every five years per 40 CFR (e). The tune ups must meet the requirements listed in 40 CFR Notifications and Reports Algonquin is required to submit an Initial Notification pursuant to 40 CFR (c). Additionally, per 40 CFR (d), a Notification of Compliance Status is required stating that a tune up on the process heaters were Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-10

40 conducted. Algonquin will also be required to submit a Compliance Report every 5 years indicating that the required tune ups were conducted ADDITIONAL APPLICABLE STATE REGULATIONS This section summarizes the applicability of New York Codes, Rules and Regulations, Title 6, Parts , the NYSDEC s Division of Air Resources regulations NYCRR Emissions Testing, Sampling and Analytical Determinations As stated in Section 4.3.1, Algonquin is required to conduct performance tests under 40 CFR 60 Subpart KKKK for the new turbines at the facility. 6 NYCRR provides requirements for emissions testing in New York. 6 NYCRR Required emissions tests In accordance with 6 NYCRR the Stony Point compressor station must submit an acceptable report of measured NO X emissions from the three new turbines within a stated time within the Title V permit or 40 CFR 60 Subpart KKKK, whichever is sooner. 6 NYCRR Notification Unless otherwise specified in the Title V permit, the Stony Point compressor station will notify the Department of the time and date of the 40 CFR 60 Subpart KKKK NO X performance test, in writing, by no later than 30 days prior to the scheduled date of the test. The notification will include the acceptable procedures that will be used to stack test including sampling and analytical procedures NYCRR Air Pollution Prohibited The Stony Point compressor station will not cause any particulate, fume, gas, mist, odor, smoke, vapor, pollen, toxic or deleterious emissions, either alone or in combination with others, to be emitted to the outdoor atmosphere in such quantity, characteristic or duration which are injurious to human, plant or animal life or to property, or which unreasonably interfere with the comfortable enjoyment of life or property. Algonquin will continue to comply with this site wide requirement NYCRR Particulate Emissions 6 NYCRR establishes particulate emission limits for stationary combustion installations. No limits are established for the combustion of gaseous fuels. As all new combustion units at the Stony Point compressor station will be fired with natural gas, the particulate emission limits in this section do not apply NYCRR Opacity Pursuant to 6 NYCRR (a), the three new Mars 100 turbines, the new emergency generator, and the new fuel gas heaters will not exhibit greater than 20 percent opacity (six minute average), except for one six minute period per hour of not more than 27 percent opacity. In accordance with 6 NYCRR (b)(3), compliance with the opacity standard may be determined by considering credible evidence. Existing combustion units complies with the opacity requirement by firing only natural gas. As stated in the Permit Review Report accompanying the facility s current Title V permit, opacity is Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-11

41 required to be measured upon request due to use of clean burning natural gas. Algonquin proposes to comply with the opacity requirement for the proposed combustion units by firing only natural gas in the units NYCRR Reasonably Available Control Technology (RACT) For Major Facilities of Oxides of Nitrogen (NO X ) NO x RACT requirements apply to emission sources at major facilities of NO x. The NO x RACT applicability for the new emission units at the Stony Point compressor station are provided below. New Turbines Pursuant to 6 NYCRR (e)(1), simple cycle combustion turbines are subject to a NO x emission limit of 50 ppmvd, corrected to 15 percent oxygen, for sources designed to burn gaseous fuels (gaseous fuels include, but are not limited to, natural gas, landfill gas, and digester gas) only. 18 The three new turbines will meet this emission limit, as indicated by the vendor guarantee listed in Table 3 1. Compliance with this emission limit will be determined with a one hour average during the ozone season and a 30 day average during the non ozone season as required under 6 NYCRR (e)(1). New Emergency Generator Pursuant to 6 NYCRR (f)(6), the emergency generator proposed to be installed at the Stony Point compressor station is exempt from NOx RACT requirements because it qualifies as an emergency power generating stationary internal combustion engine. New Heaters The new heaters are other combustion sources with potential hourly emissions less than 3 lbs/hour. As such, they are not subject to the NOX RACT requirements per 6 NYCRR (g) NYCRR 617 State Environmental Quality Review Most projects proposed by a state agency or local government and all discretionary approvals (i.e., permits) from a New York State agency must go through State Environmental Quality Review (SEQR), codified in 6 NYCRR 617. The proposed project at the Stony Point compressor station is not required to submit Environmental Assessment Forms (EAF) because the project is also regulated by FERC. The FERC environmental assessment supersedes the NYSDEC SEQR review DISPERSION MODELING REQUIREMENTS Division of Air Resources Policy 1 (DAR-1): Guidelines for the Control of Toxic Ambient Air Contaminants Policy DAR 1 provides guidance for the control of toxic ambient air contaminants in New York State and describes the Division of Air Resources basic programmatic guidelines for making air toxics related permitting decisions. Appendix B of DAR 1 establishes requirements for Ambient Air Quality Impact Screening Analyses. Such an analysis must be completed for all new or modified sources of air contaminants regulated under 6 NYCRR Part 212. Pursuant to 6 NYCRR 212.2, the section applies to process emission sources. Process is defined under 6 NYCRR 212.1(b)(5) as follows: 18 The requirement to submit a proposal for RACT and an evaluation of NO x control technologies under 6 NYCRR 6 NYCRR (e)(3) applies to combined cycle combustion turbines only, according to Mike Jennings, NYSDEC (call with Trinity Consultants on February 11, 2014). The presumptive limits for simple cycle and regenerative combustion turbines remain in effect after July 1, Confirmed in a call with George Sweikert, NYSDEC Region 3 Regional Air Pollution Control Engineer, on February 11, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-12

42 Any industrial, commercial, agricultural or other activity, operation, manufacture or treatment in which chemical, biological, and/or physical properties of the material or materials are changed, or in which the material(s) is conveyed or stored without changing the material(s) (where such conveyance or storage system is equipped with a vent(s) and is non mobile), and which emits air contaminants to the outdoor atmosphere. A process does not include an open fire, operation of a combustion installation, or incineration of refuse other than by products or wastes from processes. The new turbines, the new emergency generator, and the new fuel gas heaters qualify as combustion installations and are therefore not considered processes. Therefore, an Ambient Air Quality Impact Screening Analysis is not required for these units under the DAR 1 policy. However, Algonquin is proactively submitting a DAR 1 analysis for the new emission units at the facility based on guidance received from the Impact Assessment and Meteorology Section of the NYSDEC s Division of Air Resources in order to streamline the permit review process. 20 Algonquin understands that the NYSDEC s current unwritten policy is to request a DAR 1 analysis for all permit applications submitted for natural gas compressor stations in New York. The DAR 1 analysis is included in Appendix H. The analysis compares the long term (annual) and short term (1 hour) impacts of toxics emitted by the project to the New York State Annual Guidance Concentrations (AGCs) and Short term Guidance Concentrations (SGCs) NAAQS Modeling Analysis Although a NAAQS modeling analysis is not required for the proposed project at the Stony Point compressor station per PSD requirements, Algonquin is proactively submitting a NAAQS analysis of the facility, post project, based on guidance received from the Impact Assessment and Meteorology Section of the NYSDEC s Division of Air Resources in order to streamline the permit review process. 21 Algonquin understands that the NYSDEC s current unwritten policy is to request a NAAQS analysis for all permit applications submitted for natural gas compressor stations in New York. The NAAQS analysis is included in Appendix H. The analysis provides facility wide ambient impacts of all regulated pollutants for which NAAQS have been established. 20 Per call with Margaret Valis, Chief, Impact Assessment and Meteorology Section, on August 5, Per call with Margaret Valis, Chief, Impact Assessment and Meteorology Section, on August 5, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 4-13

43 5. BACT ANALYSIS 5.1. BACT REQUIREMENTS Algonquin has determined that a Prevention of Significant Deterioration (PSD) review is required for the Project at Stony Point compressor station in accordance with 6 NYCRR for greenhouse gases (GHGs). As such, Algonquin is required to conduct a PSD best available control technology ( BACT ) analysis for each emission source that is part of the proposed modification per 6 NYCRR EPA does not currently foresee a need to promulgate National Ambient Air Quality Standard (NAAQS) or PSD Increment standards for GHG pollutants; therefore, an air quality analysis is not a required element of PSD review for GHGs. In addition, GHGs are not known to cause any impairment to visibility or adverse impacts on soils and vegetation; therefore, it is concluded that the additional impact analyses per 6 NYCRR is not required for GHG PSD. Per EPA s guidance, the BACT review is considered as a surrogate analysis for visibility, soils, and vegetation analyses and no additional analyses are required. 22 BACT is defined in 6 NYCRR (b)(9) as follows: An emissions limitation based on the maximum degree of reduction for each air pollutant subject to regulation under the act which would be emitted from or which results from any proposed major facility or NSR major modification which the department, on a case by case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such proposed major facility or NSR major modification through application of production processes or available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of such air pollutant. In no event shall application of BACT result in emissions of any air pollutant which would exceed the emissions allowed by any applicable standard established pursuant to section 7411 or 7412 of the act. Emissions from any source utilizing clean fuels, or any other means, to comply with this paragraph shall not be allowed to increase above levels that would have been required under this paragraph as it existed prior to enactment of the Clean Air Act amendments of This definition applies to all pollutants triggering PSD. However, there are several GHG specific considerations under this BACT definition that warrant further discussion. The underlined terms in the NYSDEC s BACT definition above are addressed further below Emissions Limitation BACT is an emissions limitation and not an emission reduction rate or specific technology. While BACT is prefaced upon the application of technologies reflecting the maximum reduction rate achievable, the final result of BACT is an emission limit. This limit, would typically be expressed as an emission rate limit of a pollutant (e.g., lb/mmbtu, ppm or lb/hr). Furthermore, EPA s guidance on GHG BACT has indicated that GHG BACT limitations should be averaged over long term timeframes such as 30 or 365 day rolling averages Each Air Pollutant Since BACT applies to each air pollutant subject to regulation under the act, the BACT evaluation process is typically conducted for each regulated NSR pollutant individually and not for a combination of pollutants. For PSD applicability assessments involving GHGs, the regulated NSR pollutant subject to regulation under the Clean Air Act (CAA) is the sum of six greenhouse gases and not a single pollutant. In the final Tailoring Rule preamble, 22 PSD and Title V Permitting Guidance for Greenhouse Gases, EPA s OAQPS, March Ibid. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-1

44 EPA went beyond applying this combined pollutant approach for GHGs to PSD applicability and made the following recommendations that suggest applicants should conduct a single GHG BACT evaluation on a CO 2 e basis for emission sources that emit more than one GHG: However, we disagree with the commenter s ultimate conclusion that BACT will be required for each constituent gas rather than for the regulated pollutant, which is defined as the combination of the six wellmixed GHGs. To the contrary, we believe that, in combination with the sum of six gases approach described above, the use of the CO 2 e metric will enable the implementation of flexible approaches to design and implement mitigation and control strategies that look across all six of the constituent gases comprising the air pollutant (e.g., flexibility to account for the benefits of certain CH 4 control options, even though those options may increase CO 2 ). Moreover, we believe that the CO 2 e metric is the best way to achieve this goal because it allows for tradeoffs among the constituent gases to be evaluated using a common currency. 24 Algonquin acknowledges the potential benefits of conducting a single GHG BACT evaluation on a CO 2 e basis for the purposes of addressing potential tradeoffs among constituent gases for certain types of emission units. However, for the proposed project, the GHG emissions from natural gas combustion are driven primarily by CO 2. For combustion sources (which represent 96% of total the CO 2 e potential emissions for the project), CO 2 represents approximately 99.2% of the potential GHG emissions from this source type. As such, the focus of the following top down GHG BACT analysis for the turbines, emergency generator and heaters is focused on CO 2. Further, for fugitive emission sources (which represent 4% of total CO 2 e potential emissions for the project), CO 2 represents only 0.2% of the potential GHG emissions from this source type, while CH 4 accounts for the remaining 99.8%. As such, the focus of the following top down GHG BACT analysis for the equipment leaks and gas releases is focused on CH Proposed Modification BACT applies to the type of source (e.g., major facility or major NSR modification ) proposed by the applicant. Historically, EPA has not considered the BACT requirement as a means to redefine the project design. The applicant defines the source (i.e., its goals, aims and objectives). However, the scope of the applicant s ability to define the source is not absolute. A key task for the reviewing agency is to determine which parts of the proposed process are inherent to the applicant s purpose and which parts may be changed without changing that purpose. Algonquin has provided project discussion and definition in Section 5.2, below, to aid the technical reviewers in need and scope of this project and how GHG BACT should be reviewed in light of this detailed information. The Algonquin Stony Point compressor station is an existing stationary source. Thus, the BACT review is limited to the new and physically modified emissions units. Existing sources and components that may have associated emission increases due to the project are not affected emission units and as such are not subject to BACT GHG EMISSION SOURCES SUBJECT TO BACT The GHG emission sources that are part of the proposed project and are therefore subject to BACT analysis are: Combustion Sources Simple Cycle Natural Gas Fired Combustion Turbines (15,900 bhp (ISO) Solar Mars 100 turbines) Ancillary natural gas fired fuel gas heaters (Cameron 1.2 MMBTU/hr heat input units) FR 31,531, Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule; Final Rule, June 3, 2010 Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-2

45 Ancillary Natural Gas Fired Emergency Engine (585 bhp Waukesha emergency generator engine) Process (Methane) Sources: Piping Component Leaks Gas Releases Simple-Cycle Natural Gas-Fired Combustion Turbine As previously discussed, Algonquin is proposing to install two new Solar Mars 100 turbines as compressor drivers at Stony Point compressor station as part of the AIM Project. Additionally, the existing Solar Mars 90 turbine will be upgraded to a Mars 100 unit as part of the AGT project. The combustion of natural gas in these turbines produces GHG emissions of CO 2, CH 4, and N 2 O. More than 99% of these combustion related GHG emissions are in the form of CO 2 on a mass basis, since each carbon atom combusted in the fuel stream essentially results in one molecule of CO 2 emissions. 25 CH 4 and N 2 O emissions are byproducts of the combustion reactions and are formed in much lower quantities. Even when scaling CH 4 and N 2 O by their relative GWPs, these constituents combined contribute less than 1% of the total GHG emissions (on a CO 2 e basis) resulting from the combustion of natural gas and process gas. The proposed project designs requires the use of natural gas as fuel for the new turbine driven compressors as it can be locally sourced and other fuels are not readily available at the location and/or are more carbon intensive than natural gas. The proposed project does not rely on alternative or backup fuels. A simple cycle turbine was selected as it is the most energy efficient mode of compressing natural gas that is feasible at the proposed site location. The use of a combined cycle process is infeasible for the following reasons: Combined cycle processes recover heat from the exhaust of the combustion turbines to produce steam as a product, and/or to drive a steam turbine generator to produce electricity. The Stony Point compressor station does not have any process needs or capacity for the amount of additional steam or power that would be generated. The compression demand at a transmission compressor station such as Stony Point is not stable and may fluctuate significantly. Combined cycle combustion turbines are most effective at steady, predictable loads. Further, they take time to bring on line as the heat recovery loop must be heat saturated before power can be derived. As such, simple cycle combustion turbines are necessary for the design of this project to accommodate the rapid deployment and frequent load changes inherent in transmission compressor station operations. In comparison to other similar compressor turbines, the Solar Mars 100 is a state of the art industrial turbine that offers equivalent or better energy efficiency than other models of similar size, operated in a simple cycle. With a heat rate of 7,382 Btu/hp hr (vendor specified performance based on the lower heating value of natural gas and 0 o F ambient temperature), the selected turbine is a highly efficient model. GHG control technologies available specifically for this type of source are to be reviewed further under the five (5) step, top down BACT analysis that follows Ancillary Natural Gas-Fired Equipment In addition to the turbines described above, Algonquin is proposing to install miscellaneous new emission units to support the compression project. These new sources include a 585 hp Waukesha VGF24GL natural gas fired 25 Although small fractions of fuel carbon convert to combustion byproducts such as CO, or are unreacted CH4, the majority of carbon combusted in the fuel stream is converted to CO2. Consequently, standard emission factors for CO2 are developed by assuming that the fuel carbon completely oxidizes to CO2 (i.e., oxidation factor = 1.00). Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-3

46 emergency generator and three (3) small Cameron natural gas fired fuel gas heaters, each with a rated heat output capacity of MMBtu/hr. As noted in the description of the turbine compressor, the location and scope of the project dictates the use of natural gas as fuel, even for these small, miscellaneous combustion sources, as other fuels are not readily available at the location and/or are more carbon intensive than natural gas. Furthermore, because these miscellaneous combustion sources are small, their combined total potential emissions represent a small fraction (approximately 1%) of the project s total potential GHG emissions, on a CO 2 e basis. As such, these small sources have an inconsequential impact on the overall project s emissions to the environment Process (Methane) Sources Typical sources of fugitive emissions from natural gas compressor stations include leaks from piping components (valves, flanges, connectors and open ended lines) as well as gas release events (i.e., blowdowns). The vast majority of emissions from gas release events are associated with startup, shutdown, or maintenance activities. The proposed project at Stony Point will include the addition and modification of piping to accommodate the new turbines as well as the addition of a gas cooler at the site. Further, the station will continue to have gas releases, including potential releases from the newly installed equipment, after the project. These sources of fugitive emissions have the potential to release methane (as well as small amounts of CO 2 ) due to its primary composition in natural gas and other process streams. As previously mentioned, unlike the turbines, whose GHG emissions are driven by CO 2, GHG releases from these fugitive emissions sources are driven by methane, with approximately 99.8% of the potential fugitive CO 2 e a result of CH 4. However, in comparison to the new combustion sources, the combined potential fugitive emissions are only a small fraction (4%) of the project s total GHG emissions, on a CO 2 e basis PROJECTED EMISSIONS OF GHG The methodology used to estimate project emissions potentials of GHG is described in Section 3 of this application report and detailed calculations are presented in Appendix B. Table 5 1 provides a summary of the post project potential GHG emissions on both a mass and CO 2 e basis from each of the affected emission units at the Stony Point compressor station. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-4

47 Table 5 1: Summary of Post Project GHG Potential Emissions for New Sources Post Project PTE Emission Unit ID Emissions Unit Description CO 2 (tpy) CH 4 (tpy) N 2 O (tpy) CO 2 e 1 (tpy) Percent of Total CO 2 e STON TBC 07 New Turbine 07 Mars , , % STON TBC 08 New Turbine 08 Mars , , % STON TBC 09 New Turbine 09 Mars , , % STON ENGEN 02 New Emergency Generator Waukesha VGF24GL % STON GHTR New Fuel Gas Heaters Cameron % STON PC Equipment Leaks Piping Components 1 33 NA % STON GR Gas Releases NA 8, % 214, % FERC PDF (Unofficial) 9/29/2014 4:29:38 PM 1 CO2e emissions are calculated using the global warming potentials listed under 40 CFR Part 98, Table A 1, as Algonquin will be required to use these global warming potentials in calculating greenhouse gas emissions for submittal under 40 CFR Part 98. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-1

48 5.4. GHG BACT ASSESSMENT METHODOLOGY This section discusses the approach used in completing the BACT analyses for the proposed project. The primary document referenced for the general BACT methodology is EPA s 1990 NSR Workshop Manual (Draft), Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Permitting. 26 Recently, U.S. EPA issued the following guidance documents related to the completion of GHG BACT analyses, which were utilized as resources in completing the GHG BACT evaluation for the proposed project: PSD and Title V Permitting Guidance For Greenhouse Gases 27 Air Permitting Streamlining Techniques and Approaches for Greenhouse Gases: A Report to the U.S. Environmental Protection Agency from the Clean Air Act Advisory Committee; Permits, New Source Reviews and Toxics Subcommittee GHG Permit Streamlining Workgroup; Final Report 28 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and Institutional Boilers 29 In PSD and Title V Permitting Guidance for Greenhouse Gases, EPA recommended that the traditional five step top down BACT process be used to determine BACT for GHGs. EPA has explained how the top down BACT analysis process works on a case by case basis. In brief, the top down process provides that all available control technologies be ranked in descending order of control effectiveness. The PSD applicant first examines the most stringent or "top" alternative. That alternative is established as BACT unless the applicant demonstrates, and the permitting authority in its informed judgment agrees, that technical considerations, or energy, environmental, or economic impacts justify a conclusion that the most stringent technology is not "achievable" in that case. If the most stringent technology is eliminated in this fashion, then the next most stringent alternative is considered, and so on. To assist applicants and regulators with the case by case process, in 1990 EPA issued a Draft Manual on New Source Review permitting which included a top down BACT analysis. The five steps in a top down BACT evaluation can be summarized as follows: Step 1. Identify all possible control technologies; Step 2. Eliminate technically infeasible options; Step 3. Rank the technically feasible control technologies based upon emission reduction potential; Step 4. Evaluate ranked controls based on energy, environmental, and/or economic considerations; and Step 5. Select BACT. While the top down BACT analysis is a procedural approach suggested by U.S. EPA policy, 30 this approach is not specifically mandated as a statutory requirement of the BACT determination. Further, this EPA recommended 26 U.S. EPA, October U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, (Research Triangle Park, NC: March 2011) (September 2012). 29 U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, (Research Triangle Park, NC: October 2010) In November 2010, the U.S. EPA issued a guidance document for the permitting of GHGs that recommends that permitting authorities use the same top-down BACT process to determine BACT for GHGs. U.S. EPA Office of Air and Radiation, Office of Air Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-1

49 five step process can be directly applied to GHGs without any significant modifications. However, the process is conducted on a unit by unit, pollutant by pollutant basis and only considers the portions of the facility that are considered emission units as defined under the PSD regulations. 31 For criteria pollutants, the least stringent emission rate allowable for BACT is any applicable limit under either New Source Performance Standards (NSPS Part 60) or National Emission Standards for Hazardous Air Pollutants (NESHAP Parts 61). Since no GHG limits have been incorporated into any existing, final NSPS or Part 61 NESHAPs that are applicable to the proposed project, nor has the NYSDEC SIP provided for any applicable GHG emissions limitations, no floor for a GHG BACT analysis is available for consideration. The following steps were taken for each affected unit subject to BACT for this project Step 1 - Identify Control Technologies Available control technologies for CO 2 e with the practical potential for application to the emission unit are identified. The application of demonstrated control technologies in other similar source categories to the emission unit in question can also be considered. While identified technologies may be eliminated in subsequent steps in the analysis based on technical and economic infeasibility or environmental, energy, economic or other impacts, control technologies with potential application to the emission unit under review are identified in this step. Under Step 1 of a criteria pollutant BACT analysis, the following resources are typically consulted when identifying potential technologies: 1. EPA s Reasonably Available Control Technology (RACT)/Best Available Control Technology (BACT)/Lowest Achievable Emission Reduction (LAER) Clearinghouse (RBLC) database; 2. Determinations of BACT by regulatory agencies for other similar sources or air permits and permit files from federal or state agencies; 3. Engineering experience with similar control applications; 4. Information provided by air pollution control equipment vendors with significant market share in the industry; and/or 5. Review of literature from industrial technical or trade organizations. Trinity Consultants performed searches of the RBLC database in February 2014 to identify the emission control technologies and emission levels that were determined to be BACT by permitting authorities since GHGs became regulated pollutants for emission sources comparable to the proposed facility. The following categories were searched: Commercial/Institutional Size Boilers/Furnaces (< 100 MMBtu/hr) Gaseous Fuels & Gaseous Fuel Mixtures (RBLC Code ) Commercial/Institutional Size Boilers/Furnaces (< 100 MMBtu/hr) Natural Gas (includes propane and liquefied petroleum gas) (RBLC Code ) Large Combustion Turbines (> 25 MW) Simple Cycle (no waste heat recovery) (RBLC Code ) Large Combustion Turbines (> 25 MW) Simple Cycle (no waste heat recovery) Natural Gas (includes propane & liquefied petroleum gas) (RBLC Code ) Large Internal Combustion Engines (> 500 hp) Natural Gas (includes propane & liquefied petroleum gas) (RBLC Code ) Quality Planning and Standards, PSD and Title V Permitting Guidance for Greenhouse Gases, November 2010,page 18, 31 Pursuant to 40 CFR 52.21(a)(7), emission unit means any part of a stationary source that emits or would have the potential to emit any regulated NSR pollutant. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-2

50 Additionally, the RBLC results for CO 2 e involving fugitive emissions were reviewed. Upon completion of the RBLC search, Trinity then reviewed relevant vendor information, pending permit applications, and issued permits not included in the RBLC. U.S. EPA s top down BACT analysis procedure also recommends the consideration of inherently lower emitting processes as available control options under Step 1. For GHG BACT analyses, low carbon intensity fuel selection is the primary control option that can be considered a lower emitting process. As a natural gas pipeline compressor station, Algonquin proposes the use of pipeline quality natural gas only for all on site combustion equipment. Table C 1 of 40 CFR Part 98 shows CO 2 emissions per unit heat input (MMBtu) for wide variety of industrial fuel types. Only landfill and other biomass gases (captured methane) and coke oven gas result in lower CO 2 emissions per unit heat input than natural gas; however, as biomass gases and coke oven gas are not readily available for the Stony Point compressor station, Algonquin is proposing to use the available fuel type with the lowest carbon intensity. It should be noted that EPA s GHG BACT requirements suggests that Carbon Capture and Sequestration (CCS) be evaluated as an available control for projects with large amounts of potential CO 2 e emissions (i.e., where CO 2 e emissions levels are in the order of 1,000,000 tpy CO 2 e), or for industrial facilities with high purity CO 2 streams. The proposed project s emissions are well below this recommended threshold, and the turbine exhaust cannot be considered a high purity CO 2 stream (turbine exhaust has a high flowrate and relatively low CO 2 concentration). Per EPA s guidance, CCS is not feasible for projects of smaller profiles such as the proposed Project. 32 Further, Trinity was unable to identify a facility like Stony Point where CCS technology has been successfully installed and implemented for similar turbines. As technology is currently evolving with respect to the CCS option, it has been included as a potentially technically feasible control technology in this analysis as discussed in Section Step 2 - Eliminate Technically Infeasible Options After the available control technologies have been identified, each technology is evaluated with respect to its technical feasibility in controlling GHG emissions from the source in question. The first question in determining whether or not a technology is feasible is whether or not it is demonstrated. If so it is feasible. Whether or not a control technology is demonstrated is considered to be a relatively straightforward determination. Demonstrated means that it has been installed and operated successfully elsewhere on a similar facility. This step should be straightforward for control technologies that are demonstrated if the control technology has been installed and operated successfully on the type of source under review, it is demonstrated and it is technically feasible. 33 An undemonstrated technology is only technically feasible if it is available and applicable. A control technology or process is only considered available if it has reached the licensing and commercial sales phase of development and is commercially available. 34 Control technologies in the R&D and pilot scale phases are not considered available. Based on EPA guidance, an available control technology is presumed to be applicable if it 32 PSD and Title V permitting Guidance for Greenhouse Gases. March 2011, pages Also, see Report of the Interagency Task Force on Carbon Capture and Storage, page NSR Workshop Manual (Draft), Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Permitting, page B NSR Workshop Manual (Draft), Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Permitting, page B.18. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-3

51 has been permitted or actually implemented by a similar source. Decisions about technical feasibility of a control option consider the physical or chemical properties of the emissions stream in comparison to emissions streams from similar sources successfully implementing the control alternative. The NSR Manual explains the concept of applicability as follows: An available technology is "applicable" if it can reasonably be installed and operated on the source type under consideration. 35 Applicability of a technology is determined by technical judgment and consideration of the use of the technology on similar sources as described in the NSR Manual Step 3 - Rank Remaining Control Technologies by Control Effectiveness All remaining technically feasible control options are ranked based on their overall control effectiveness for GHG. For GHGs, this ranking may be based on energy efficiency and/or emission rate Step 4 - Evaluate Most Effective Controls and Document Results After identifying and ranking available and technically feasible control technologies, the economic, environmental, and energy impacts are evaluated to select the best control option. If adverse collateral impacts do not disqualify the top ranked option from consideration it is selected as the basis for the BACT limit. Alternatively, in the judgment of the permitting agency, if unreasonable adverse economic, environmental, or energy impacts are associated with the top control option, the next most stringent option is evaluated. This process continues until a control technology is identified. The energy, environment, and economic impacts analysis under Step 4 of a GHG BACT assessment presents a unique challenge with respect to the evaluation of CO 2 and CH 4 emissions. The technologies that are most frequently used to control emissions of CH 4 in hydrocarbon rich streams (e.g., flares and thermal oxidizers) actually convert CH 4 emissions to CO 2 emissions. Consequently, the reduction of one GHG (i.e., CH 4 ) results in a proportional increase in emissions of another GHG (i.e., CO 2 ). Permitting authorities have historically considered the effects of multiple pollutants in the application of BACT as part of the PSD review process, including the environmental impacts of collateral emissions resulting from the implementation of emission control technologies. To clarify the permitting agency s expectations with respect to the BACT evaluation process, states have sometimes prioritized the reduction of one pollutant above another. For example, technologies historically used to control NO X emissions frequently caused increases in CO emissions. Accordingly, several states prioritized the reduction of NO X emissions above the reduction of CO emissions, approving low NO X control strategies as BACT that result in higher CO emissions relative to the uncontrolled emissions scenario Step 5 - Select BACT In the final step, the BACT emission limit is determined for each emission unit under review based on evaluations from the previous step. Although the first four steps of the top down BACT process involve technical and economic evaluations of potential control options (i.e., defining the appropriate technology), the selection of BACT in the fifth step involves an evaluation of emission rates achievable with the selected control technology. BACT is an emission limit unless technological or economic limitations of the measurement methodology would make the imposition of an emissions standard is infeasible, in which case a work practice or operating standard can be imposed. 35 NSR Workshop Manual (Draft), Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Permitting, page B.18. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-4

52 5.5. COMBUSTION TURBINES GHG BACT The following section presents BACT evaluations for GHG emissions from the proposed new gas turbines Step 1 Identify All Control Technologies A review of RBLC entries for control options related to CO 2 e emissions from simple cycle turbines shows that the only control methods listed are: Use of High Efficiency Turbines; Good Combustion/Operating Practices; and Fueled by Natural Gas As discussed in the previous section, CCS is also considered in this analysis. The following table summarizes the potential CO 2 control strategies for simple cycle combustion turbines that will be analyzed. Table 5 2: Potential CO 2 Control Strategies for Combustion Turbines Control Strategy Carbon Capture and Storage (CCS) Optimum Turbine Efficiency Fuel Selection Good Combustion/Operating Practices Description System that captures CO2 in the turbine exhaust and transfers it to permanent storage Selection of turbine with high efficiency ratings Combustion of low carbon intensity fuel Adherence to good combustion practices Step 2 Eliminate Technically Infeasible Options Carbon Capture and Sequestration An effective CCS system would require three elements: Separation technology for the CO 2 exhaust stream (i.e., carbon capture technology), Transportation of CO 2 to a storage site, and A viable location for long term storage of CO 2. These three elements work in series. To execute a CCS program as BACT, all three elements must be available. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-5

53 CO 2 Capture CCS would involve post combustion capture of the CO 2 from the combustion turbines and sequestration of the CO 2 in some fashion. Carbon capture is an established process in some industry sectors, although not in the natural gas transmission sector (i.e., for compressor stations). In theory, carbon capture could be accomplished with low pressure scrubbing of CO 2 from the exhaust stream with either solvents (e.g., amines and ammonia), solid sorbents, or membranes. However, only solvents have been used to date on a commercial (slip stream) scale, and solid sorbents and membranes are only in the R&D phase. In terms of post combustion CCS for power plants, the following projects have taken place on slip streams at coal fired power plants: 36, First Energy R.E. Burger (Dec Dec. 2010): First Energy conducted a CO 2 capture pilot test using Powerspan s ECO 2 technology on a 1 MWe slipstream from the outlet of the R.E. Burger Station (near Shadyside, Ohio) demonstration scale 50 MW ECO unit (Powerspan s multipollutant control system). The ECO 2 CO 2 capture system uses a proprietary ammonia based solvent in a thermal swing absorption (TSA) process to remove CO 2 from the flue gas. An independent review of the pilot test indicated that technology is ready for scale up for use in commercial scale (200 MW or larger) generating plants. To date, this technology has not been scaled up to any known commercial scale operations AES Warrior Run (2000 Present) and Shady Point (1991 Present): AES captures 66, ,000 tpy CO 2 using the ABB/Lummus monoethanolamine (MEA) solvent based system from a small slipstream of the MWe coal fired circulating fluidized bed (CFB) power plants at its stations in Cumberland, Maryland and Panama, Oklahoma. The CO 2 is not stored, but rather is used in the food processing industry and related processes. 3. IMC Chemicals (formerly Searles Valley Minerals) (1978 Present): IMC Chemicals captures 270,000 tpy CO 2 from the flue gas of two MW industrial coal boilers using amine scrubbing technology at its soda ash production plant in Trona, California. The captured CO 2 is used for the carbonation of brine from Searles Lake, and the brine is subsequently used in the soda ash production process WE Energy Pleasant Prairie (June 2008 Oct. 2009): WE Energy captured 15,000 tpy CO 2 using Alstom s chilled ammonia process from a 5 MWe slipstream of the 1,210 MW coal fired power plant at its Pleasant Prairie station in Pleasant Prairie, Wisconsin. The literature does not suggest the CO 2 was permanently sequestered in any geologic formation or by any other means Southern Company, Plant Barry (June 2011 to present): Southern Company at Plant Barry, a coal fired power plant in Mobile, Alabama, captures 1,50,000 tpy CO 2 using an MHI amine based process from a 25 MW slip stream of flue gas. The captured CO 2 is sequestered in the Citronelle Oil Field. 41 These projects have demonstrated the technical feasibility of small scale CO 2 capture on a slipstream of a coal fired power plant s emissions using various solvent based scrubbing processes. In addition to the coal fired power projects deploying CO 2 capture at a small scale, Florida Power & Light (FP&L) conducted CO 2 capture to 36 CCS Task Force Report, p International Energy Agency GHG Research & Development Program, RD&D Database: CO 2 Capture Commercial Projects, 38 Powerspan, FirstEnergy ECO2 Pilot Facility, Electrical Power Research Institute, CO2 Capture and Storage Newsletter, Visit to the Trona plant MEA CO2 Removal System in Trona, California, in September 2006, Issue #2 December 2006, 40 MIT Carbon Capture & Sequestration Technologies, AEP Alstom Mountaineer Fact Sheet: Carbon Dioxide Capture and Storage Project, November 23, 2011, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-6

54 produce tons per day (tpd) CO 2 using the Fluor Econamine FG SM scrubber system on 15 percent of the flue gas from its 320 MWe 2 1 natural gas cycle unit in Bellingham, Massachusetts from 1991 to Due to increases in natural gas prices in , FP&L changed from a base/intermediate load plant to a peaking plant, which made the continued operation of the capture plant uneconomical. The captured CO 2 was compressed and stored on site for sale to two nearby major food processing plants. 42, 43 Although this project indicates small scale CO 2 capture is technically feasible for natural gas combined cycle combustion turbine (CCCT) flue gas, it does not support the availability of full scale CO 2 capture from simple cycle combustion turbines (SCCT). The projects identified do not propose post combustion capture of CO 2 from a SCCT, which is the type of turbine being installed at Stony Point. Similarly, the routine fluctuation in operation of the compressor station turbines would make implementation of post combustion capture difficult. Moreover, the projects identified are for post combustion capture on pulverized coal (PC) plants or a natural gas CCCT (in one case) using a slip stream versus the full exhaust stream. Also, the exhaust from a PC plant would have a significantly higher concentration of CO 2 in the slipstream as compared to a more dilute stream from the combustion of natural gas (approximately percent for a coal fired system versus 3 4 percent for a natural gas fired system). 44 In addition, prior to sending the CO 2 stream to the appropriate sequestration site, it is necessary to compress the CO 2 from near atmospheric pressure to pipeline pressure (around 2,000 psia). The compression of the CO 2 would require a large auxiliary power load, resulting in additional fuel (and CO 2 emissions) to generate the same amount of power. 45 While carbon capture technology may be technologically available on a small scale, it has not been demonstrated in practice for full scale natural gas compressor stations. CCS is not commercially available as BACT at present for the turbines given the limited deployment of only slipstream/demonstration applications of CCS. CO 2 Transport CO 2 capture has not been demonstrated in practice on a compressor station and therefore not commercially available as BACT; furthermore, even if capture were demonstrated, sequestration of the captured CO 2 would pose its own barriers to the use of CCS as BACT. Accordingly, Algonquin is including a discussion on the feasibility of transporting the CO 2 captured from the exhaust of the SCCTs to an appropriate sequestration site. Either Algonquin would need to transport the captured CO 2 to an existing CO 2 pipeline, or transport the CO 2 to a site with recognized potential for storage (e.g., enhanced oil recovery [EOR] sites). The Worldwide Carbon Capture and Storage Database (WCCUS) 46 provides a map of potential storage locations. All of the potential sites within the surrounding area are still in the development phase or did not pass validation and as such future phases were cancelled. 47 In reality, the closest active injection sites, which are still 42 International Energy Agency GHG Research & Development Program, RD&D Database: Florida Light and Power Bellingham CO2 Capture Commercial Project, 43 Reddy, Satish, et. al., Fluor s Econamine FG PlusSM Technology for CO2 Capture at Coal-fired Power Plants, Power Plant Air Pollutant Control Mega Symposium, August 25-28, 2008, Baltimore, Maryland, 44 CCS Task Force Report, August 2010, p CCS Task Force Report, August 2010, p Information on the wetlands reclamation projects being considered for soil carbon sequestration is located at: Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-7

55 in development phase, are located in the Upper Peninsula of Michigan and in Central Illinois, both of which are over 1,000 miles from the station. Of these two sites, the Michigan site appears to be more developed and possibly open to receiving CO 2 from outside sources in the future. Field Studies are in process to use the Triassic Newark Basin for sequestration. 48 In addition, the New York State Geological Survey (NYSGS) has identified three potential sequestration sites in the state s oil and gas fields. 49 Projects are underway to assess their validity. While the locations in New York are not active injection sites, for the purposes of this analysis, the closest potential location was selected. Refer to Figure 5 1 below for a map illustrating the location of the closest potential CO 2 sequestration site. 50 Figure 5 1. CO 2 Potential Injection Location Figure 5 1: Green Marker indicates location of the Triassic Newark Basin Study currently underway to examine potential for large scale, permanent storage of CO2 in deep strata of the Newark Rift Basin. There are no known CO 2 pipelines near the station or within the region. 51,52 It is technically feasible to construct a CO 2 pipeline to either of these sequestration sites. 48 Information on the results of the Triassic Newark Basin field project is located at: This map is taken directly from: Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-8

56 CO 2 Storage The process of injecting CO 2 into subsurface formations for long term sequestration is referred to as geologic CO 2 storage. CO 2 can be stored underground in oil/gas fields, unmineable coal seams, and saline formation. In practice, CO 2 is currently injected into the ground for enhanced oil and gas recovery. Per the CCS Task Force Report, approximately 50 million tonnes of CO 2 per year are injected during enhanced oil and gas recovery operations. Within the MRCSP region, which includes New York, alternatives to subsurface injection have been considered but have yet to prove valid. 53 Examples include marshlands reclamation projects New Jersey and Maryland. Internationally, there are three large scale projects that are currently in operation worldwide as follows: The Sleipner Project (1996 current): One million tonnes of CO 2 per year is separated from produced natural gas in Norway and is injected into Utsira Sand (high permeability, high porosity sandstone) 1,100 meters below the sea surface. 2. The Weyburn Project ( ): 1.8 million tonnes of CO 2 per year is injected into 29 horizontal and vertical wells into two adjacent carbonate layers in Saskatchewan, Canada near the North Dakota border. The CO 2 originates from a nearby synfuel plant The Snohvit Project (2010 current): The project is expected to inject 0.7 million tonnes CO 2 per year from natural gas production operations near the Barents Sea. The injection well reaches 2,600 meters beneath the seabed in the Tubasen sandstone formation. 4. The In Salah Project (2004 current): The project injects 1.2 million tonnes of CO 2 annually produced from natural gas into 1,800 meter deep muddy sandstone (low porosity, low permeability). For the purposes of this analysis, it is assumed that CO 2 storage is a technically feasible option for Algonquin to employ for CO 2 emissions from the new turbines at the Stony Point compressor station. In conclusion, despite the significant technical challenges discussed earlier in implementing CCS technology on turbines of this size, in addition to the fact that CCS has not been achieved in practice for a natural gas compressor station, Algonquin is conservatively assuming that CCS is technically feasible for the purposes of this BACT analysis. As such, Algonquin is providing an economic feasibility assessment to support the argument on why CCS is not a legitimate technology for use as GHG BACT on the SCCTs Optimum Turbine Efficiency The affected units for this project are as follows, with information per the specifications provided by Solar. 56 Two new Solar Mars S4 with a power output ratings of 15,900 hp (ISO) and rated engine efficiency of 34.4%. Upgrade of existing Solar Mars 90 to meet above Mars 100 specifications. 53 Midwest Regional Carbon Sequestration Partnership (MRCSP) maintains a website at 54 CCS Task Force Report, Pages C-1 and C Petroleum Technology Research Centre, 56 Solar Turbines, Mars 100 Gas Turbine Compressor Set, General Specifications, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-9

57 As previously stated, the Solar Mars 100 is a state of the art industrial turbine that offers equivalent or better energy efficiency than other models of similar size, operated in a simple cycle. With a heat rate of 7,382 Btu/hphr (vendor specified performance based on the lower heating value of natural gas and 0 o F ambient temperature), the selected turbine is a highly efficient model. The Mars 100 is a simple cycle design. As discussed in Section 5.2.1, combined cycle turbines are not appropriate for the proposed project Fuel Selection The fuel for firing the combustion turbines is natural gas only. As discussed in Section 5.4.1, natural gas has the lowest carbon intensity of any available fuel for such units and its use is technically feasible for this project Good Combustion/Operating Practices Good combustion/operating practices are a potential control option for optimizing the fuel efficiency of the combustion turbines. Natural gas fired combustion turbines typically operate in a lean pre mix mode to ensure an effective staging of air/fuel ratios in the turbine to maximize fuel efficiency and minimize incomplete combustion. Furthermore, the proposed turbine is sufficiently automated to ensure optimal fuel combustion and efficient operation leaving virtually no need for operator tuning of these aspects of operation Step 3 Rank Remaining Control Options by Effectiveness The following control options remain and are ranked by their effectiveness in reducing CO 2 emissions from the turbines. Details of these technologies are provided in Step 1. CCS, 90% 57 Use of high efficiency turbines, fueled by natural gas and employing good combustion/operating practices (Base Case). In terms of comparing relative heat rates and efficiencies, similar models and sizes of industrial simple cycle gas turbines suitable for use in natural gas compression from leading manufacturers are ranked by efficiency in Table 5 3 below. 57 Capture efficiency of 90% is assumed by NETL in its costing document, Estimating Carbon Dioxide Transport and Storage Costs, Page 9. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-10

58 Table 5 3: Comparison of Turbine Heat Rates and Efficiencies Manufacturer Model Output (hp) Heat Rate (Btu/hp hr) 58 Efficiency Solar 59 Mars ,900 7, % General Electric 60 GE ,068` 7, % Siemens 61 SGT ,000 7, % As shown, the Solar Mars 100 turbine is one of the most efficient models of generally available mechanical drive turbines in the needed HP range presented. The Solar model also has the advantage of a lower vendorguaranteed NO X emission rate than the other models shown Step 4 Top-Down Evaluation of Control Options Carbon Capture and Storage As the most stringent control option available, CCS would be considered BACT, barring the consideration of its energy, environmental, and/or economic impacts. However, for the reasons outlined in this section, this option should not be relied upon as BACT and the next most stringent alternative evaluated. The flue gas stream from the turbine stacks will be significantly lower in CO 2 concentrations than exhaust streams that have demonstrated capture of CO 2 for sequestration. As such, additional processing of the exhaust gas will be required to implement CCS for the project. These steps include separation (removal of other pollutants from the waste gases), capture, and compression of CO 2, transfer of the CO 2 stream and sequestration of the CO 2 stream. These processes require additional equipment to reduce the exhaust temperature, compress the gas, and transport the gas via pipelines. These units would require additional electricity and generate additional air emissions, of both criteria pollutants and GHG pollutants. This would result in negative environmental and energy impacts. Algonquin has opted to include a cost feasibility assessment for use of CCS to support the argument that while CCS could be considered to be technically feasible, it not a viable option for this project. The costs associated with CCS can be broken down into the same three categories that the CCS process is divided: CO 2 Capture, CO 2 Transport, and CO 2 Storage Carbon Capture Costs Carbon capture costs have been estimated using published articles and government resources in the absence of cost data or specific technology details for the capture of CO 2. Capture and compression costs vary widely depending on what type of combustion equipment and process is used at the facility. Of the plant configurations for which cost factors are provided in the CCS Task Force Report, the factor for a new natural gas combined cycle facility, while not the same process, is taken to be the most applicable. Capture and compression costs typically use either a CO 2 Captured or a CO 2 Avoided basis. The CO 2 captured basis accounts for all CO 2 that is 58 As reported by the manufacturers at ISO conditions, for shaft output, and based on LHV of natural gas. 59 Solar Turbines, Mars 100 Gas Turbine Compressor Set, General Specifications, 60 GE Energy Gas Turbine Data Sheet Mechanical Drive, 61 SGT-400 Industrial Gas Turbine Mechanical Drive, Specifications Sheet, Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-11

59 removed from the process as a result of the installation and use of a control technology, without including any losses during transport and storage or emissions from the control technology itself. A CO 2 avoided basis takes into account the CO 2 losses during transport and storage as well as CO 2 emissions from equipment associated with the implementation of the CCS system. It is more appropriate to use the CO 2 captured monetary estimates because the BACT analysis is based on emissions from a single source (e.g., the direct emissions from the SCCTs) and does not account for secondary emissions (e.g., the GHG emissions generated from the act of compressing the CO 2 to pipeline pressures). As such, the cost factor which uses a CO 2 captured basis is selected for use in this analysis. It should also be noted that for this analysis, the factors which appear in the CCS Task Force Report have been converted from a metric tons basis to a short tons basis and scaled from December 2009 dollars to March 2014 (current) dollars using appropriate price indices. 62 A ten year lifespan is used for the capital calculations because the acidic nature of CO 2 will deteriorate the equipment at a more aggressive rate Carbon Transport Costs The cost of pipeline installation and operation are obtained from the National Energy Technology Laboratory (NETL) s Document Quality Guidelines for Energy System Studies Estimating Carbon Dioxide Transport and Storage Costs DOE/NETL 2010/1447. Per this document, the pipeline costs include pipeline installation costs, other related capital costs, and operation and maintenance (O&M) costs. The closest carbon sequestration site, which is still in the experimental phase, is the Newark Basin located within 10 miles of the project location. For cost estimation purposes, a pipeline length of 10 miles is assumed for a CO 2 transfer pipeline laid straight from the project site location to the carbon sequestration site. NETL guidance 63 suggests that a 4 diameter pipeline would be appropriate for this transport need Geological Storage Costs The NETL s Estimating Carbon Dioxide Transport and Storage Costs document contains the average saline formation depths and capacities. As previously indicated in the transportation section, the pipeline is headed to a gas or oil reservoir, which may hold different dimensions than a saline formation. However, due to the small impact on overall calculations and the small amount of CO 2 being sequestered, this is considered to be a reasonable estimate. The average storage site depth is 1,236 meters, each injection well is able to accommodate an average of 10,320 tons per day. The Algonquin facility would be sequestering tons per day, and therefore would only require one injection well. It should be noted that differences in formation properties could have a significant effect on the project design, such as limiting the throughput to a well, thereby increasing the number of wells needed and increasing storage costs. However, due to uncertainty of the effect of the differences in the storage formations, the storage costs estimated in the NETL guidance are used in this analysis in order to not overestimate costs Overall Cost of Carbon Capture and Sequestration Including the capture costs for CO 2 emissions related to the turbine, the cost to transport emissions from the turbine, and the cost to sequester the resulting supercritical fluid into an appropriate site is estimated to be 62 Price indices are obtained from the Producer Price Index published by the U.S. Bureau of Labor Statistics. PPI values obtained from historic tables. Accessed online 02/12/2014 at 63 Figure 4: Pipe Diameter as a Function of CO 2 Flow Rate, Estimating Carbon Dioxide Transport and Storage Costs, Page Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-12

60 $164 per ton of CO 2 captured. Considering the quantity of CO 2 generated, this figure represents an unreasonable cost for GHG control that results in the classification of CCS for Algonquin s turbines as not cost effective. 64 In addition to its direct costs, CCS creates substantial indirect economic, environmental, and energy impacts. The energy impacts of CCS implementation include the costs of on site CO 2 compression and purification, and further CO 2 compression at the wellhead. Additional combustion sources could be necessary to provide energy to these processes. Further, Algonquin anticipates additional costs to inquire about and secure a carbon storage site that is within a reasonable distance and that will accept the CO 2 stream. Based on our research, it will be difficult to find such a site for this location. For multiple reasons, including the uncertainty of locating a carbon storage site, the undue burden of applying a technology that has yet to be proven for gas turbines, and the excessive cost to implement this technology, CCS is eliminated from further review. Use of high efficiency turbines, fueled by natural gas and employing good combustion/operating practices are the remaining control technologies and represent the base case Step 5 Select BACT Establishing an appropriate averaging period for the BACT limit is a key consideration under Step 5 of the BACT process. Localized GHG emissions are not known to cause adverse public health or environmental impacts. Rather, EPA has determined that GHG emissions are anticipated to contribute to long term environmental consequences on a global scale. Accordingly, EPA s Climate Change Workgroup has characterized the category of regulated GHGs as a global pollutant. Since localized short term health and environmental effects from GHG emissions are not recognized, Algonquin proposes only annual GHG BACT limits. As such, CO 2 BACT for this project is proposed in Table 5 4. The resulting BACT standard is a proposed annual emissions limitation of 67,916 tons CO 2 e/year/turbine for each of the new turbines (07, 08 and 09) on a 12 month rolling average basis. The emission rate is based on the maximum expected hourly emissions during normal operation, as calculated in Appendix B. The maximum hourly emissions are based on operation of the turbine at 100% load at an ambient temperature of 0 F. For compliance purposes, CO 2 e emissions are calculated using the global warming potentials listed under 40 CFR part 98, Table A 1, as Algonquin will be required to use these global warming potentials in calculating annual greenhouse gas emissions for submittal under 40 CFR Part 98. Compliance with the proposed BACT limit will be demonstrated by monitoring fuel consumption and performing calculations consistent with those found in Appendix B. These calculations will be performed on a monthly basis to ensure that the 12 month rolling average ton CO 2 e /year emission rates do not exceed this limit. 64 For comparison, USEPA evaluated a PSD application from ETC Texas Pipeline, Ltd, submitted March 15, 2012, for a gas processing plant in Ganado, TX. In its application, ETC Texas Pipeline evaluated the cost of an 8-inch diameter, 120-mile CO 2 pipeline using the same document from NETL. ETC found the control cost per ton associated with CO 2 transport to be $80.80 per ton of CO 2. On May 24, 2012, USEPA issued a final permit that did not require CCS for this facility. Calpine Corporation also submitted a GHG PSD application to USEPA for a gas-fired power station at the Deer Park Energy Center on September 1, Calpine estimated the costs of post-combustion CCS at the facility to be between $44.11 and $ per ton of CO 2, using scalable cost estimation methods for gas-fired power stations. In its statement of basis for its draft permit issued August 2, 2012, USEPA stated that CCS at this facility would be financially prohibitive due to the overall cost of GHG control strategies. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-13

61 Table 5 4: GHG BACT for Turbines Unit Pollutant BACT Emission/Operating Limit Turbine 07 CO 2 e High efficiency turbine; Fueled by natural gas; and Good combustion/operating practices 67,916 tons CO 2 e/year, 12 month rolling average basis Turbine 08 Turbine 09 CO 2 e CO 2 e High efficiency turbine; Fueled by natural gas; and Good combustion/operating practices High efficiency turbine; Fueled by natural gas; and Good combustion/operating practices 67,916 tons CO 2 e/year, 12 month rolling average basis 67,916 tons CO 2 e/year, 12 month rolling average basis Through the proposed BACT limit, Algonquin limits the maximum fuel consumption and CO 2 emissions, effectively requiring efficient operation at the design heat rate, when operating at 100% load (as inefficient turbine operation would require additional fuel consumption which is undesirable from an operator s perspective). Algonquin will operate Turbines 07, 08 and 09 under an Operations and Maintenance (O&M) Plan to ensure that the units are operated in accordance with recommended good combustion practices such that optimum efficiency is maintained. Furthermore, the proposed units contain modern process control technology that continually seeks optimum efficiency from the turbine. Because the lb CO 2 e/hr emission rate from the turbine is lower during startup and shutdown than during normal operation, Algonquin proposes that the requested BACT limit applies at all times. Because cold weather operation of the turbine may result in instantaneous lb CO 2 e/hr emission rates higher than the proposed annual average limit and conversely lower in warm weather operation, the requested BACT limit is only appropriate on a 12 month rolling average basis EQUIPMENT LEAKS GHG BACT The following section presents BACT evaluations for GHG (predominantly CH 4 ) emissions from new piping components that will be installed as part of this project. Piping components that produce fugitive emissions at the proposed project include: valves, pressure relief valves, pump seals, compressor seals, and sampling connections. Potential emissions from the new piping components account for approximately 0.4 % of the total estimated increase in GHG emissions due to the proposed project. GHG emissions from leaking pipe components (fugitive emissions) include CH 4 and CO 2. However, Algonquin estimates that 99.85% of CO 2 e emissions from fugitive leaks is methane. Due to the relatively small contribution that this emission source has to total GHG emissions from the project, a less detailed BACT review is warranted. However, since this source type has been addressed via top down analysis in other GHG BACT submittals for compressor stations to date, a similar analysis is included here to be complete Step 1 Identify All Control Technologies In determining whether a technology is available for controlling GHG emissions from fugitive components, available permits, permit applications, industry guidance and EPA s RBLC were consulted. Based on these resources, the following available control technologies were identified: 65 Installing leakless technology piping components instead of traditional components; 65 Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-14

62 Implementing a leak detection and repair (LDAR) program; Implementing an audio/visual/olfactory (AVO) monitoring program; and Implementing an alternative monitoring program It should be noted that the only fugitive GHG control technology identified by the RBLC is the use of an LDAR program. However, there are no natural gas transmission compressor stations listed in the RBLC at the time of submittal of this application Step 2 Eliminate Technically Infeasible Options Leakless Technology Leakless technology valves are available and currently in use, primarily where highly toxic or otherwise hazardous materials are used. These technologies are generally considered cost prohibitive except for specialized service. Some leakless technologies, such as bellow valves, if they fail, cannot be repaired without a unit shutdown that often generates additional emissions. Further, it is not accurate to assume that leakless components do not leak over the lifetime of the component or that their use would result in zero emissions. In the September 27, 2013 response to Sierra Club s comment letter on draft permit PSD TX GHG, ExxonMobil stated that, For example, the valve packing configurations noted by the BAAQMD permits for refineries noted by the Sierra Club, such as bellow sealed valves and live loaded packed valves do leak. Bellow seals can fail, live load packing wears and leaks, etc. 66 In addition, high process temperatures can cause degradation of leakless components, such as bellow valves, which can reduce the useful life of the component. Recognizing that leakless technologies have not been universally adopted as LAER or BACT, even for toxic or extremely hazardous services, it is reasonable to state that these technologies are impractical for control of the low amounts GHG emissions generated by this project and will not be considered further in this analysis LDAR LDAR programs have traditionally been developed for the control of VOC emissions. BACT determinations related to control of VOC emissions rely on technical feasibility, economic reasonableness, reduction of potential environmental impacts, and regulatory requirements for these instrumented programs. Monitoring direct emissions of CO 2 is not feasible with the normally used instrumentation for fugitive emissions monitoring. However, instrumented monitoring is technically feasible for components in CH 4 service. As such, LDAR technology is considered technically feasible for this project AVO Methods Leaking fugitive components can be identified through audio, visual, or olfactory (AVO) methods. The natural gas that passes through the Stony Point compressor station is odorized and therefore natural gas leaks from components are expected to have discernible odor to some extent, making them detectable by olfactory means. A large leak can be also detected by sound (audio) and sight. The visual detection can be a direct viewing of leaking gases, or a secondary indicator such as condensation around a leaking source due to cooling of the expanding gas as it leaves the leak interface. As such, AVO methods (including audio or visual) are considered technically feasible for this project Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-15

63 Alternative Monitoring Program Alternative monitoring programs have been demonstrated to be effective in detecting leaks at natural gas industry facilities. Under Subpart W of the Mandatory GHG Reporting Rule, 40 CFR (q) requires leak detection monitoring at least annually for equipment leaks from the following component types at natural gas transmission compression stations that emit 25,000 metric tons CO 2 e or more per year of GHGs: valves, connectors, open ended lines, pressure relief valves, and meters. The Stony Point compressor station currently complies with this monitoring requirement which may use any of the following methods of leak detection as outlined in 40 CFR (a): optical gas imaging instrument, Method 21 monitoring, infrared laser beam illuminated instrument, or acoustic leak detection device. As such, an alternative monitoring program is considered technically feasible for this project Step 3 Rank Remaining Control Options by Effectiveness The remaining control technologies are an LDAR program, an alternative monitoring program, and AVO methods. The following list provides a ranking of the remaining control technologies based on their approximate control efficiencies: LDAR Programs, 40 97% efficient depending on the component type 67 Alternative Monitoring Programs control efficiency unknown AVO Methods and Alternative Monitoring Programs control efficiency unknown for natural gas service LDAR programs require instrumented monitoring of piping components above a diameter of 2 inches and employs Method 21 testing for leaks, which requires the use of traditional organic vapor analyzers (OVA). It should be noted that approximately 40% or more of the natural gas piping components in question are less than 2 inches in diameter. The analyzers can identify concentrations of compounds up to the defined detection limits of the analyzer. To comply with the 40 CFR Part 98 monitoring requirements at Stony Point, Algonquin employs remote sensing using infrared (IR) imaging equipment. IR equipment are cameras that are able to visualize gas by utilizing the physics of fugitive gas leaks. The camera allows the user to see fugitive gas emissions as plumes. While LDAR programs only require instrumented monitoring of piping components above a diameter of 2 inches, smaller diameter piping components are captured by infrared imaging. 40 CFR Part 98, Subpart W requires monitoring of all systems with tubing greater than ½ inch in diameter. The use of IR imaging equipment enables detection of small leaks from several meters away and large leaks from several hundred meters away. As such, the use of IR imaging is assumed to be more effective than traditional OVA used for Method 21 for LDAR programs due to the detection limitations of OVA. Audio/visual/olfactory means of identifying leaks owes its effectiveness to the frequency of observation opportunities. Those opportunities arise as operating technicians make rounds, inspecting equipment during those routine tours of the operating areas. The Stony Point facility is classified as an unmanned site. While someone may be present at the site during the daytime work shift, there are periods during which no one will be at the site. Further, AVO is typically used for inorganic/odorous and low vapor pressure compounds such as chlorine, ammonia, hydrogen sulfide, and hydrogen cyanide. This method cannot generally identify leaks at as 67 Per Technical Support Document for NSPS OOOO, this is based on emission reductions at refineries that were obtained for various components from EPA s recently collected data for the Uniform Standards. In the Technical Support Document, EPA states that this data represents the most up-to-date information that is available for equipment leaks from the oil and gas sector. The reductions do not include uncontrolled piping components less than two inches in diameter. The NSPS OOOO technical support document references a Memorandum from Cindy Hancy, RTI to Jodi Howard, EPA, Analysis of Emission Reduction Techniques for Equipment Leaks, December 21, 2011, EPA-HQ-OAR as the basis for these reductions. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-16

64 low a leak rate as instrumented readings can identify and therefore it is generally used to supplement an LDAR monitoring program. It should be noted that the detection level of an alternate monitoring program utilizing infrared imaging equipment would be much higher than the detection level of AVO. As such, its effectiveness as a stand alone control technology is relatively low for the Stony Point facility and therefore is ranked below the alternate monitoring program option used for 40 CFR Part 98 compliance described above Step 4 Top-Down Evaluation of Control Options The fourth of the five steps in the top down BACT assessment procedure is to evaluate the most effective control and document the results. This step has been performed for each remaining control technology on the basis of economic, energy, and environmental considerations, and is described in the following sections. In this step, once an option is selected no further (i.e., lower ranking) options are assessed. In its recent review of the NSPS for the Oil and Gas Sector, EPA evaluated LDAR for the control of fugitive VOCs at transmission compressor stations, but found that it is only cost effective to control VOC emissions via LDAR at gas processing plants and not transmission compressor stations. 68 For this application, an economic analysis was conducted to determine the cost of implementing an LDAR program on the new fugitive components at Stony Point compressor station. The analysis was based on the information provided by EPA in its recent review of NSPS standards for the gas industry (NSPS OOOO) which used LDAR cost and control efficiency data recently collected by EPA for the development of the Uniform Standards. 69 The installation of an LDAR system for the fugitive components will cost approximately $150 $300 per ton of CO 2e removed, depending on the level of monitoring performed. The cost analysis is provided in Appendix J. As previously indicated, USEPA has found GHG control strategy costs ranging from $80 $100 per ton to be financially prohibitive in previous GHG PSD determinations. As such, an LDAR program is considered an economically infeasible control option for the new fugitive components at Stony Point Step 5 Select BACT Algonquin proposes to utilize an alternative monitoring program to identify fugitive leaks in accordance with the requirements under 40 CFR 98 as described above PROCESS GAS RELEASES GHG BACT The proposed project may result in additional gas releases at the Stony Point compressor station due to periodic blowdown of the new turbines. These emissions are associated with turbine startup, shutdown, and maintenance activities. Similar to fugitive components, the GHG emissions from gas releases from the proposed project include CH 4 and CO 2. Also, the potential emissions from gas releases, when conservatively estimated for permitting purposes in this application, account for approximately 4 percent of the GHG emissions from the proposed project. As GHG emissions from gas releases are relatively low, a less detailed BACT review is warranted. Based on RBLC search results, there are no documented available technologies to reduce emissions of CH 4 from gas release events at natural gas compression stations. As such, no additional controls are available to reduce these emissions and Algonquin will continue to implement best operational practices as BACT to reduce emissions during gas release events. 68 Background Supplemental Technical Support Document for the Final NSPS, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution, US EPA OAQPS, April 18, 2012, p Background Supplemental Technical Support Document for the Final NSPS, Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution, US EPA OAQPS, April 18, 2012, Appendix C. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-17

65 5.8. ANCILLARY COMBUSTION UNITS GHG BACT A review of RBLC entries for control options related to CO 2 e emissions from heaters and emergency generators shows that the only control methods listed are: Good Combustion/Operating Practices; and Fueled by Natural Gas As demonstrated above for the turbines, CCS is not a feasible option for this project. The emergency generator will run for standby power only for no more than 500 hours per year, and is restricted to no more than 100 hours per year operation for testing and maintenance per 40 CFR 60, Subpart JJJJ. The engine will burn only pipeline quality natural gas, will be operated in accordance with good combustion practices and will comply with 40 CFR 60, Subpart JJJJ requirements for stationary spark ignition RICE which requires efficient design to minimize emissions. As such, GHG BACT for the emergency generator is the use of an efficiently designed generator engine firing pipeline natural gas. Similarly, the proposed fuel gas heaters are small units that are exempt from permitting and have the potential to contribute < 1% of the total potential CO 2 e emissions from the project. Proposed BACT for these insignificant sources will be the use of low carbon intensity fuel (i.e., pipeline quality natural gas), selection of an efficient heater design, and good combustion and operating practices. Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants 5-18

66 APPENDIX A: FACILITY PLOT PLAN Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

67

68 APPENDIX B: DETAILED EMISSION CALCULATIONS AND VENDOR SPECS Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

69 Prevention of Significant Deterioration (PSD) Netting Calculation Summary: Table 1 Project Emission Potential (Step 1) Unit Description Potential to Emit (PTE) 2 Stony Point Compressor Station CO 2 e (NYSDEC GWPs) 1 CO 2 e (EPA GWPs) 1 NOx CO PM 10 SO 2 Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Baseline Project Baseline Project Baseline Project Baseline Project Baseline Project Baseline Actual Emission Potential Actual Emission Potential Actual Emission Potential Actual Emission Potential Actual Emission Potential to Actual Emissions Potential to Emit Emissions Potential to Emit Emissions Potential to Emit Emissions Potential to Emit Emissions Potential Emit Emissions (BAE) 3 (PEP) 4 (PTE) 2 (BAE) 3 (PEP) 4 (PTE) 2 (BAE) 3 (PEP) 4 (PTE) 2 (BAE) 3 (PEP) 4 (PTE) 2 (BAE) 3 (PEP) 4 (PTE) 2 (BAE) 3 New Units: STON TBC 07 5 Replaced with a Mars 100 turbine (9 ppm) 67,854 NA 67,854 67,916 NA 67, NA NA NA NA 2 STON TBC 08 New Mars 100 turbine (9 ppm) 67,854 NA 67,854 67,916 NA 67, NA NA NA NA 1.9 STON TBC 09 New Mars 100 turbine (9 ppm) 67,854 NA 67,854 67,916 NA 67, NA NA NA NA 1.9 STON ENGEN 02 New Waukesha Emergency Generator 263 NA NA NA NA NA NA STON GHTR 02 New Cameron Heater 199 NA NA NA NA NA NA STON GHTR 03 New Cameron Heater 397 NA NA NA NA NA NA STON-PW New Parts Washer - NA - - NA - - NA - - NA - - NA - - NA - Fugitive STON-PC New Fugitive Piping Components 694 NA NA NA - - NA - - NA - - NA - Fugitive STON-GR New Fugitive Gas Releases 7,279 NA 7,279 8,663 NA 8,663 - NA - - NA - - NA - - NA - Associated Units: Fugitive STON-TK 6 Fugitives - Tanks Fugitive STON-TL 6 Fugitive - Truck Loading PEP 212, , The global warming potentials (GWPs) listed under 6 NYCRR , Table 9 (NYSDEC GWPS) differ from the GWPs listed under 40 CFR Part 98, Table A-1 (EPA GWPs). As requested by NYSDEC during the pre-application meeting on April 1, 2014, 2e CO emissions have been calculated using the GWPs listed under 6 NYCRR for comparison to the PSD significant project thresholds. However, for compliance purposes, CO 2e emissions are also calculated using the GWPs under 40 CFR Part Potential to emit is provided for new and existing sources. 3. The Baseline period selected for the project is January December For new units: PEP = PTE; For existing units, PEP = PTE - BAE. Although PEP is defined as projected actual emissions (PAE) - BAE for existing units at a major facility under 6 NYCRR (b)(40)(i)(c), PTE is used in place of PAE as permitted under 6 NYCRR (b)(41)(ii). 5. STON TBC 07 will be replaced with a Mars 100 unit. Algonquin will be obtaining ERCs for the shutdown of the existing STON TBC 07 as shown in Table Associated units will not be physically modified with the project. For these units, PTE will not increase as a result of the project, but an increase in actual emissions is possible. Although PEP is defined as PAE - BAE for existing units at a major facility under 6 NYCRR (b)(40)(i)(c), PTE is used in place of PAE The actual increase in fugitive emissions (PAE - BAE) is not currently defined for these sources. Table 2 Project Emission Potential (Step 1) Project Emission Potential (PEP) FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Pollutant Project Emission Potential (PEP) (tpy) Significant Project Threshold Significant (SPT) Project 2 (tpy) 1 (Yes/No)? CO 2 e (NYSDEC GWPs) 212,442 75,000 Yes NO Yes CO No PM No SO No 1. Significant project threshold from Table 6 of 6 NYCRR The netting is complete and PSD is not triggered for pollutants without a significant PEP. Thus, CO, PM 10, and SO 2 do not trigger PSD and no further netting is required. Algonquin Gas Transmission, LLC AIM and AGT Projects Page 1 of 26 PSD Summary

70 Prevention of Significant Deterioration (PSD) Netting Calculation Summary: Step 2: Contemporaneous Changes and ERCs Contemporaneous Period Estimated Start of Construction Date 1 Start of Contemporaneous Period 2 There were no emissions increases in the Contemporaneous Period. Table 3 Proposed ERCs: Mar-16 Mar-11 NO x ERCs 1 Unit Description (tpy) Shutdown Units: STON EN 01 Clark TLA STON EN 02 Clark TLA STON EN 03 Clark TLA STON EN 04 Clark TLA Replaced Units: STON TBC 07 Modified to S Total ERCs Used: Table 4 Net Emission Increases (Step 2): Pollutant Net Emission Increase 1 (NEI) (tpy) Significant Net Emission Increase Threshold (SNEIT) 2 (tpy) Significant Project (Yes/No)? Stony Point Compressor Station 1. Per 6 NYCRR 231-4(b)(12), "commence construction" is defined as the date on which the owner or operator has all necessary preconstruction approvals or permits (including those permits or approvals required under Federal air quality control laws and those which are part of the State Implementation Plan) and has either: (i) begun, or caused to begin, a continuous program of actual construction, to be completed within a reasonable time as determined by the department; or (ii) entered into binding agreements or contractual obligations, which cannot be canceled or modified without substantial loss to the owner or operator, to undertake a program of actual construction to be completed within a reasonable time as determined by the department. 2. Per 6 NYCRR 231-4(b)(13), "contemporaneous" is defined as the period beginning five years prior to the scheduled commence construction date of the new or modified emission source, and ending with the scheduled commence operation date. 1. As documented in the ERC application submitted with this permit modification. Per 6 NYCRR , ERCs are quantified as the difference between BAE and subsequent PTE. Additional ERCs are generated, but not used, for replaced Turbine 07 and shutdown Engines FERC PDF (Unofficial) 9/29/2014 4:29:38 PM CO 2 e (NYSDEC GWPs) 212,442 75,000 Yes NO No CO No 3 PM No 3 SO 2-40 No 1. The net emissions increase is defined under 6 NYCRR (b)(30) as the aggregate increase in emissions of a regulated NSR contaminant in tpy at an existing major facility resulting from the sum of: (i) the project emission potential of the modification; (PEP can be found in Table 1) (ii) every creditable emission increase at the facility which is contemporaneous and for which an emission offset was not obtained; and (No creditable contemporary increasese) (iii) any ERC at the facility, or portion thereof, selected by the applicant which is contemporaneous and which was not previously used as part of an emission offset, an internal offset, or relied upon in the issuance of a permit under this (ERCs Part. can be found in Table 3) 2. Significant net emission increase threshold from Table 6 of 6 NYCRR Netting was completed in Step 1 for CO, PM 10, and SO 2. Algonquin Gas Transmission, LLC AIM and AGT Projects Page 2 of 26 PSD Summary

71 Non-Attainment New Source Review (NNSR) Netting Calculation Summary: Table 1 Project Emission Potential (Step 1) Unit Description Potential to Emit (PTE) 1 Stony Point Compressor Station NO x VOC PM 2.5 SO 2 (as a PM 2.5 precursor) Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Baseline Project Baseline Project Baseline Project Baseline Actual Emission Potential Actual Emission Potential Actual Emission Potential Actual Emissions Potential to Emit Emissions Potential to Emit Emissions Potential to Emit Emissions (BAE) 2 PEP 3 (PTE) 1 (BAE) 2 PEP 3 (PTE) 1 (BAE) 2 PEP 3 (PTE) 1 (BAE) 2 New Units: STON TBC 07 4 Replaced with a Mars 100 turbine (9 ppm) 19.0 NA NA NA NA 1.9 STON TBC 08 New Mars 100 turbine (9 ppm) 19.0 NA NA NA NA 1.9 STON TBC 09 New Mars 100 turbine (9 ppm) 19.0 NA NA NA NA 1.9 STON ENGEN 02 New Waukesha Emergency Generator 0.6 NA NA NA NA STON GHTR 02 New Cameron Heater 0.2 NA NA NA NA STON GHTR 03 New Cameron Heater 0.3 NA NA NA NA STON-PW New Parts Washer - NA NA NA - - NA - Fugitive STON-PC New Fugitive Piping Components - NA NA NA - - NA - Fugitive STON-GR New Fugitive Gas Releases - NA NA NA - - NA - Associated Units: Fugitive STON-TK 5 Fugitives - Tanks Fugitive STON-TL 5 Fugitive - Truck Loading PEP Potential to emit is provided for new and existing sources. 2. The Baseline period selected for the project is January December For new units: PEP = PTE; For existing units, PEP = PTE - BAE. Although PEP is defined as projected actual emissions (PAE) - BAE for existing units at a major facility under 6 NYCRR (b)(40)(i)(c), PTE is used in place of PAE as permitted under 6 NYCRR (b)(41)(ii). 4. STON TBC 07 will be replaced with a Mars 100 unit. Algonquin will be obtaining ERCs for the shutdown of the existing STON TBC 07 as shown in Table Associated units will not be physically modified with the project. For these units, PTE will not increase as a result of the project, but an increase in actual emissions is possible. Although PEP is defined as PAE - BAE for existing units at a major facility under 6 NYCRR (b)(40)(i)(c), PTE is used in place of PAE - BAE. The actual increase in fugitive emissions (PAE - BAE) is not currently defined for these sources. Project Emission Potential PEP FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Table 2 Project Emission Potential (Step 1): Pollutant Project Emission Potential (tpy) Significant Project Threshold (SPT) (tpy) 1 Significant Project 2 (Yes/No)? VOC Yes NO x Yes PM Yes SO 2 as PM 2.5 Precursor No NOx as PM 2.5 Precursor Yes 1. Significant project threshold from Table 3 and Table 4 of 6 NYCRR The netting is complete and NNSR is not triggered for pollutants without a significant PEP. Thus, SO 2 as a PM 2.5 precursor do not trigger NNSR and no further netting is required. Algonquin Gas Tranmission, LLC AIM and AGT Projects Page 3 of 26 NNSR Summary

72 Non-Attainment New Source Review (NNSR) Netting Calculation Summary: Step 2: Contemporaneous Changes and ERCs Contemporaneous Period Estimated Start of Construction Date 1 Mar-16 Start of Contemporaneous Period PM 2.5 and PM 2.5 Precursors 2 Mar-11 Start of Contemporaneous Period NO x and VOC There were no emissions increases in the Contemporaneous Period. Table 3 Proposed ERCs: Unit Description NO x VOC PM 2.5 ERCs 1 (tpy) ERCs 1 (tpy) ERCs 1 (tpy) Shutdown Units: STON EN 01 Clark TLA STON EN 02 Clark TLA STON EN 03 Clark TLA STON EN 04 Clark TLA Replaced Units: STON TBC 07 Modified to S Total ERCs Used: Table 4 Net Emission Increases (Step 2): Stony Point Compressor Station 1. Per 6 NYCRR 231-4(b)(12), "commence construction" is defined as the date on which the owner or operator has all necessary preconstruction approvals or permits (including those permits or approvals required under Federal air quality control laws and those which are part of the State Implementation Plan) and has either: (i) begun, or caused to begin, a continuous program of actual construction, to be completed within a reasonable time as determined by the department; or (ii) entered into binding agreements or contractual obligations, which cannot be canceled or modified without substantial loss to the owner or operator, to undertake a program of actual construction to be completed within a reasonable time as determined by the department. 2. Per 6 NYCRR 231-4(b)(13), "contemporaneous" is defined as the period beginning five years prior to the scheduled commence construction date of the new or modified emission source, and ending with the scheduled commence operation date. In the severe ozone nonattainment area, for emissions of VOC or NO x only, contemporaneous is definsed as the five consecutive calendar year period which ends with the calendar year that the proposed modification is scheduled to commence operation. 1. As documented in the ERC application submitted with this permit modification. Per 6 NYCRR , ERCs are quantified as the difference between BAE and subsequent PTE. More VOC, NO x, and PM 2.5 ERCs were generated by the project than are used in the netting analysis FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Pollutant Net Emission Increase 1 (NEI) (tpy) Significant Net Emission Increase Threshold (SNEIT) 2 (tpy) Significant Project (Yes/No)? VOC No NO x No PM No SO 2 as PM 2.5 Precursor 3-40 No NO x as PM 2.5 Precursor No 1. The net emissions increase is defined under 6 NYCRR (b)(30) as the aggregate increase in emissions of a regulated NSR contaminant in tpy at an existing major facility resulting from the sum of: (i) the project emission potential of the modification; (PEP can be found in Table 1) (ii) every creditable emission increase at the facility which is contemporaneous and for which an emission offset was not obtained; and (No creditable contemporary increasese) (iii) any ERC at the facility, or portion thereof, selected by the applicant which is contemporaneous and which was not previously used as part of an emission offset, an internal offset, or relied upon in the issuance of a permit under this Part. (ERCs can be found in Table 3) 2. Significant net emission increase threshold from Table 3 and Table 4 of 6 NYCRR Netting was completed in Step 1 for SO 2 as a PM 2.5 precursor. Algonquin Gas Tranmission, LLC AIM and AGT Projects Page 4 of 26 NNSR Summary

73 Proposed PSD Emission Reduction Credits (ERCs) Unit Description Potential to Emit (PTE) Stony Point Compressor Station CO 2 e 1 NOx CO PM 10 SO 2 Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Baseline Baseline Baseline Baseline Actual Potential Actual Potential Actual Potential Actual Potential Emissions to Emit Emissions to Emit Emissions to Emit Emissions to Emit (BAE) 2 ERCs 3 (PTE) (BAE) 2 ERCs 3 (PTE) (BAE) 2 ERCs 3 (PTE) (BAE) 2 ERCs 3 (PTE) Baseline Actual Emissions (BAE) 2 ERCs 3 Shutdown Units: STON EN 01 Clark TLA STON EN 02 Clark TLA STON EN 03 Clark TLA STON EN 04 Clark TLA Replaced Units: STON TBC 07 Replaced with Mars 100 turbine (9 ppm) Total ERCs: As requested by NYSDEC during the pre-application meeting on April 1, 2014, CO 2 e emissions have been calculated using the GWPs listed under 6 NYCRR for ERC generation purposes. 2. The Baseline period selected for the project is January December As documented in the ERC application submitted with this permit modification. Per 6 NYCRR , ERCs are quantified as the difference between BAE and subsequent PTE. Proposed NNSR Emission Reduction Credits (ERCs) Unit Description Potential to Emit (PTE) NOx VOC PM 2.5 SO 2 Emissions (tpy) Emissions (tpy) Emissions (tpy) Emissions (tpy) Baseline Baseline Baseline Actual Potential Actual Potential Actual Potential Emissions to Emit Emissions to Emit Emissions to Emit (BAE) 1 ERCs 2 (PTE) (BAE) 1 ERCs 2 (PTE) (BAE) 1 ERCs 2 (PTE) Baseline Actual Emissions (BAE) 1 ERCs FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Shutdown Units: STON EN 01 Clark TLA STON EN 02 Clark TLA STON EN 03 Clark TLA STON EN 04 Clark TLA Replaced Units: STON TBC 07 Replaced with Mars 100 turbine (9 ppm) Total ERCs: The Baseline period selected for the project is January December As documented in the ERC application submitted with this permit modification. Per 6 NYCRR , ERCs are quantified as the difference between BAE and subsequent PTE. Algonquin Gas Transmission, LLC AIM and AGT Projects Page 5 of 26 ERC Summary

74 TABLE B-1a - New Turbine 7, New Turbine 8 and New Turbine 9 Ambient Temperature, Start Model, and Utilization Data PTE - 100% Fuel Utilization at 100% Power Output Month #Days Daily Average Weighted Daily Average JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Annual Below 0 F Hours Below -20 F Hours 1. Please refer to TABLE B-0. Low Temperature Data NOTES 19 hrs/yr 0 hrs/yr Start Model and Utilization Utilization % Start Model AGT - Low Starts 312 starts/yr Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 6 of 26 PTE Estimates: AIM Project Revised: June 2014

75 TABLE B-1b - New Turbine 7, New Turbine 8 and New Turbine 9 Manufacturer's Operating and Emissions Data Normal Operations PTE - 100% Fuel Utilization at 100% Power Output Parameters Curve Fitting Vendor Data Ambient Temperature F Altitude ft Pressure psia Relative Humidity % 60% 60% 60% 60% 60% 60% 60% 60% 60% 60% Specific Humidity lb H2O /lb Dry Air Fuel Lower Heating Value (LHV) BTU/scf Higher Heating Value (HHV) BTU/scf 1, , , , , , , , , ,043.6 Turbine Net Output Power hp 18,150 18,150 15,730 17,612 17,612 17,075 16,376 15,442 14,336 13,105 Fuel Consumption scf/hr 142, , , , , , , , , ,658 Heat Input at LHV MMBTU/hr Heat Input at HHV MMBTU/hr Heat Rate at LHV BTU/hp-hr 7,383 7,383 7,484 7,382 7,382 7,382 7,421 7,518 7,681 7,931 Heat Rate at HHV BTU/hp-hr 8,203 8,203 8,315 8,203 8,203 8,202 8,245 8,353 8,534 8,812 Exhaust Temperature F Water Fraction %, by vol 5.76% 5.76% 6.46% 5.84% 5.84% 5.92% 6.15% 6.63% 7.56% 9.26% Non-Water Fraction %, by vol 94.24% 94.24% 93.54% 94.16% 94.16% 94.08% 93.85% 93.37% 92.44% 90.74% O 2 Content %, by vol (dry) 15.33% 15.33% 15.45% 15.37% 15.37% 15.41% 15.44% 15.46% 15.48% 15.46% Molecular Weight lb/lb-mol Flow Rate lb/hr 375, , , , , , , , , ,852 scfm (1 atm, 68 F) 84,484 84,484 76,030 82,482 82,482 80,522 78,091 75,137 71,776 67,873 acfm 210, , , , , , , , , ,668 NO X Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr CO Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr UHC Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr NOTES 1. Operating and emissions data was provided by the manufacturer for the following ambient temperatures: 0 F, 20 F, 40 F, 60 F, 80 F, and 100 F. Specific Humidity is estimate using curve fitting equation: 6.15E-04e 3.75E-02T All other parameter values estimated using cubic spline. 2. Pollutant concentrations (ppmvd at 15% O2) for 0 F and -20 F based on information provided in a document published by the manufacturer. 3. Ambient pressure and humidity will vary. However, it is believed that any variation would not affect compliance with the proposed emission representations. 4. The heating value of the natural gas used to fuel the turbine will vary. However, it is believed that any variation would not affect compliance with the proposed emission representations FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 7 of 26 PTE Estimates: AIM Project Revised: June 2014

76 TABLE B-1c - New Turbine 7, New Turbine 8 and New Turbine 9 Manufacturer's Operating and Emissions Data Startup/Shutdown Step 2: Iginition-Idle PTE - 100% Fuel Utilization at 100% Power Output Parameters Interpolated Vendor Data Ambient Temperature F Altitude ft Pressure psia Relative Humidity % 60% 60% 60% 60% 60% 60% 60% Specific Humidity lb H2O /lb Dry Air Fuel Lower Heating Value (LHV) BTU/scf Higher Heating Value (HHV) BTU/scf 1, , , , , , ,043.6 Turbine Net Output Power hp 1,573 1,761 1,708 1,638 1,544 1,434 1,310 Fuel Consumption scf/hr 29,567 29,578 29,568 29,557 29,536 29,195 28,790 Heat Input at LHV MMBTU/hr Heat Input at HHV MMBTU/hr Heat Rate at LHV BTU/hp-hr 17,654 15,775 16,259 16,947 17,966 19,121 20,641 Heat Rate at HHV BTU/hp-hr 19,615 17,528 18,065 18,831 19,963 21,246 22,935 Exhaust Temperature F Water Fraction %, by vol 3.79% 2.74% 2.99% 3.37% 4.01% 5.11% 6.98% Non-Water Fraction %, by vol 96.21% 97.26% 97.01% 96.63% 95.99% 94.89% 93.02% O 2 Content %, by vol (dry) 18.15% 18.46% 18.36% 18.24% 18.12% 18.00% 17.88% Molecular Weight lb/lb-mol Flow Rate lb/hr 152, , , , , , ,720 scfm (1 atm, 68 F) 34,211 38,181 36,743 35,185 33,818 32,310 30,773 acfm 70,755 70,694 70,815 70,610 70,748 69,978 68,921 NO X Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr CO Emissions lb/lb-mol ppmvd, 15% O 2 10,000 10,000 10,000 10,000 10,000 10,000 10,000 ppmvw 4, , , , , , , lb/hr UHC Emissions lb/lb-mol ppmvd, 15% O 2 1,000 1,000 1,000 1,000 1,000 1,000 1,000 ppmvw lb/hr NOTES 1. Footnotes 1 thru 4 of TABLE B-1b - New Turbine 7, New Turbine 8 and New Turbine FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 8 of 26 PTE Estimates: AIM Project Revised: June 2014

77 TABLE B-1d - New Turbine 7, New Turbine 8 and New Turbine 9 Manufacturer's Operating and Emissions Data Startup/Shutdown Step 3: Loading/Thermal Stabilization PTE - 100% Fuel Utilization at 100% Power Output Parameters Interpolated Vendor Data Ambient Temperature F Altitude ft Pressure psia Relative Humidity % 60% 60% 60% 60% 60% 60% 60% Specific Humidity lb H2O /lb Dry Air Fuel Lower Heating Value (LHV) BTU/scf Higher Heating Value (HHV) BTU/scf 1, , , , , , ,043.6 Turbine Net Output Power hp 4,720 5,284 5,123 4,913 4,633 4,301 3,931 Fuel Consumption scf/hr 53,288 55,409 54,951 54,163 52,875 51,224 49,276 Heat Input at LHV MMBTU/hr Heat Input at HHV MMBTU/hr Heat Rate at LHV BTU/hp-hr 10,604 9,849 10,074 10,354 10,719 11,186 11,773 Heat Rate at HHV BTU/hp-hr 11,782 10,943 11,194 11,505 11,910 12,429 13,081 Exhaust Temperature F Water Fraction %, by vol 4.56% 3.53% 3.77% 4.15% 4.77% 5.83% 7.63% Non-Water Fraction %, by vol 95.44% 96.47% 96.23% 95.85% 95.23% 94.17% 92.37% O 2 Content %, by vol (dry) 17.40% 17.69% 17.57% 17.46% 17.37% 17.28% 17.19% Molecular Weight lb/lb-mol Flow Rate lb/hr 218, , , , , , ,130 scfm (1 atm, 68 F) 48,927 55,134 52,904 50,621 48,237 45,828 43,389 acfm 109, , , , , , ,077 NO X Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr CO Emissions lb/lb-mol ppmvd, 15% O 2 9,000 9,000 9,000 9,000 9,000 9,000 9,000 ppmvw 5, , , , , , , lb/hr 1, , , , , , UHC Emissions lb/lb-mol ppmvd, 15% O ppmvw lb/hr NOTES 1. Footnotes 1 thru 4 of TABLE B-1b - New Turbine 7, New Turbine 8 and New Turbine FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 9 of 26 PTE Estimates: AIM Project Revised: June 2014

78 Make Model Normal Operating Load Operations Maximum Annual Combined Event Frequency TABLE B-1e - New Turbine 7, New Turbine 8 and New Turbine 9 Gas-Fired Turbines Maximum Emission Estimates Normal Operations, Startup, Shutdown, and Low Temperature Operations PTE - 100% Fuel Utilization at 100% Power Output Solar S4 100% Normal Startup Shutdown Startup/Shutdown w/ Normal Low Temperatures Combined Operations 8,760 hrs/yr 47 hrs/yr 44 hrs/yr 8,760 hrs/yr 19 hrs/yr 8,760 hrs/yr Pollutant Hourly Maximum Hourly Maximum Hourly Maximum Hourly Maximum Hourly Maximum Hourly Maximum Annual Annual Annual Annual Annual Annual NO X lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy CO lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy SO lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy PM 10/ lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy CO 2-e (6 NYCRR Part , Table 9 GWPs) 15,487 lb/hr 67,832 tpy 1,941 lb/hr 151 tpy 2,605 lb/hr 203 tpy 15,487 lb/hr 67,832 tpy 17,753 lb/hr 169 tpy 15,492 lb/hr 67,854 tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) 15,501 lb/hr 67,895 tpy 1,999 lb/hr 156 tpy 2,669 lb/hr 208 tpy 15,501 lb/hr 67,895 tpy 17,787 lb/hr 169 tpy 15,506 lb/hr 67,916 tpy CO 2 15,401 lb/hr 67,455 tpy 1,634 lb/hr 127 tpy 2,272 lb/hr 177 tpy 15,401 lb/hr 67,455 tpy 17,567 lb/hr 167 tpy 15,405 lb/hr 67,476 tpy N 2 O lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy TOC (Total) lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy Methane lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy Ethane lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy VOC (Total) lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy VOC (non-hap) lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy HAP (Total) lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy Acetaldehyde 3.41E-03 lb/hr 1.49E-02 tpy 6.78E-02 lb/hr 5.29E-03 tpy 1.47E-02 lb/hr 1.15E-03 tpy 4.85E-03 lb/hr 2.12E-02 tpy 7.81E-03 lb/hr 7.42E-05 tpy 4.86E-03 lb/hr 2.13E-02 tpy Acrolein 1.36E-03 lb/hr 5.98E-03 tpy 1.09E-02 lb/hr 8.47E-04 tpy 5.88E-03 lb/hr 4.59E-04 tpy 1.65E-03 lb/hr 7.22E-03 tpy 3.12E-03 lb/hr 2.97E-05 tpy 1.65E-03 lb/hr 7.24E-03 tpy Benzene 2.56E-03 lb/hr 1.12E-02 tpy 2.03E-02 lb/hr 1.59E-03 tpy 1.10E-02 lb/hr 8.61E-04 tpy 3.09E-03 lb/hr 1.35E-02 tpy 5.86E-03 lb/hr 5.56E-05 tpy 3.10E-03 lb/hr 1.36E-02 tpy Biphenyl Butadiene (1,3-) 9.17E-05 lb/hr 4.02E-04 tpy 7.29E-04 lb/hr 5.69E-05 tpy 3.95E-04 lb/hr 3.08E-05 tpy 1.11E-04 lb/hr 4.85E-04 tpy 2.10E-04 lb/hr 1.99E-06 tpy 1.11E-04 lb/hr 4.86E-04 tpy Carbon Tetrachloride Chlorobenzene Chloroform Dichloropropene (1,3-) Ethylbenzene 6.82E-03 lb/hr 2.99E-02 tpy 5.43E-02 lb/hr 4.23E-03 tpy 2.94E-02 lb/hr 2.29E-03 tpy 8.24E-03 lb/hr 3.61E-02 tpy 1.56E-02 lb/hr 1.48E-04 tpy 8.26E-03 lb/hr 3.62E-02 tpy Ethylene Dibromide Formaldehyde 1.51E-02 lb/hr 6.63E-02 tpy 1.20E+00 lb/hr 9.39E-02 tpy 6.53E-02 lb/hr 5.09E-03 tpy 3.76E-02 lb/hr 1.65E-01 tpy 3.46E-02 lb/hr 3.29E-04 tpy 3.76E-02 lb/hr 1.65E-01 tpy Hexane (n-) Methanol Methylene Chloride Methylnaphthalene (2-) Naphthalene 2.77E-04 lb/hr 1.21E-03 tpy 2.20E-03 lb/hr 1.72E-04 tpy 1.20E-03 lb/hr 9.32E-05 tpy 3.35E-04 lb/hr 1.47E-03 tpy 6.34E-04 lb/hr 6.03E-06 tpy 3.36E-04 lb/hr 1.47E-03 tpy PAH 4.69E-04 lb/hr 2.05E-03 tpy 3.73E-03 lb/hr 2.91E-04 tpy 2.02E-03 lb/hr 1.58E-04 tpy 5.67E-04 lb/hr 2.48E-03 tpy 1.07E-03 lb/hr 1.02E-05 tpy 5.68E-04 lb/hr 2.49E-03 tpy Phenol Propylene Oxide 6.18E-03 lb/hr 2.71E-02 tpy 4.92E-02 lb/hr 3.84E-03 tpy 2.67E-02 lb/hr 2.08E-03 tpy 7.47E-03 lb/hr 3.27E-02 tpy 1.41E-02 lb/hr 1.34E-04 tpy 7.49E-03 lb/hr 3.28E-02 tpy Styrene Tetrachloroethane (1,1,2,2-) Toluene 2.77E-02 lb/hr 1.21E-01 tpy 2.20E-01 lb/hr 1.72E-02 tpy 1.20E-01 lb/hr 9.32E-03 tpy 3.35E-02 lb/hr 1.47E-01 tpy 6.34E-02 lb/hr 6.03E-04 tpy 3.36E-02 lb/hr 1.47E-01 tpy Trichloroethane (1,1,2-) Trimethylpentane (2,2,4-) Vinyl Chloride Xylenes 1.36E-02 lb/hr 5.98E-02 tpy 1.09E-01 lb/hr 8.47E-03 tpy 5.88E-02 lb/hr 4.59E-03 tpy 1.65E-02 lb/hr 7.22E-02 tpy 3.12E-02 lb/hr 2.97E-04 tpy 1.65E-02 lb/hr 7.24E-02 tpy NOTES 1. It's assumed that oxidation catalyst will be ineffective during startup events. 2. CO2 = CO2 uncontrolled + CE CO-control efficiency * CO uncontrolled * (MW CO2 /MW CO ) = CO2 uncontrolled + CE CO-control efficiency * CO uncontrolled * ( / ) FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 10 of 26 PTE Estimates: AIM Project Revised: June 2014

79 Type Service JJJJ Relevant Date ZZZZ Status Make Model Fuel Fuel Higher Heating Value (HHV) Ambient Temperature Power Output Heat Rate at HHV Operating Hours Fuel Consumption Heat Input at HHV TABLE B-3 - New Emergency Generator 2 4-Stroke Lean-Burn Reciprocating Engines Hourly and Annual Emission Estimates Uncontrolled 4slb Emergency Manufactured: On or After 01/01/2009 New RICE at Major HAP Source Waukesha VGF24GL Natural Gas 1,020 BTU/scf 80 F 585 bhp (mech.) 405 kw (elec.) 7,911 BTU/hp-hr 500 hrs/yr 4,537 scfh MMscf/yr 4.63 MMBTU/hr 2,314 MMBTU/yr Uncontrolled Control Efficiency Uncontrolled Hourly Maximum Annual Pollutant NO X lb/mmscf lb/hr tpy CO 1, lb/mmscf lb/hr tpy SO lb/mmscf lb/hr tpy PM 10/ lb/mmscf lb/hr tpy CO 2-e (6 NYCRR Part , Table 9 GWPs) 232,116 lb/mmscf 1,053 lb/hr 263 tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) 253,452 lb/mmscf 1,150 lb/hr 287 tpy CO 2 120,017 lb/mmscf 545 lb/hr 136 tpy N 2 O 0.23 lb/mmscf lb/hr tpy TOC (Total) 6, lb/mmscf lb/hr tpy Methane 5, lb/mmscf lb/hr tpy Ethane lb/mmscf lb/hr tpy VOC (Total) lb/mmscf lb/hr tpy VOC (non-hap) lb/mmscf lb/hr tpy HAP (Total) lb/mmscf lb/hr tpy Acetaldehyde 3.57E+01 lb/mmscf 1.62E-01 lb/hr 4.05E-02 tpy Acrolein 2.19E+01 lb/mmscf 9.95E-02 lb/hr 2.49E-02 tpy Benzene 1.88E+00 lb/mmscf 8.52E-03 lb/hr 2.13E-03 tpy Biphenyl 9.05E-01 lb/mmscf 4.11E-03 lb/hr 1.03E-03 tpy Butadiene (1,3-) 1.14E+00 lb/mmscf 5.17E-03 lb/hr 1.29E-03 tpy Carbon Tetrachloride 1.57E-01 lb/mmscf 7.11E-04 lb/hr 1.78E-04 tpy Chlorobenzene 1.30E-01 lb/mmscf 5.89E-04 lb/hr 1.47E-04 tpy Chloroform 1.22E-01 lb/mmscf 5.52E-04 lb/hr 1.38E-04 tpy Dichloropropene (1,3-) 1.13E-01 lb/mmscf 5.11E-04 lb/hr 1.28E-04 tpy Ethylbenzene 1.69E-01 lb/mmscf 7.69E-04 lb/hr 1.92E-04 tpy Ethylene Dibromide 1.89E-01 lb/mmscf 8.58E-04 lb/hr 2.14E-04 tpy Formaldehyde 2.25E+02 lb/mmscf 1.02E+00 lb/hr 2.56E-01 tpy Hexane (n-) 4.74E+00 lb/mmscf 2.15E-02 lb/hr 5.37E-03 tpy Methanol 1.07E+01 lb/mmscf 4.84E-02 lb/hr 1.21E-02 tpy Methylene Chloride 8.54E-02 lb/mmscf 3.87E-04 lb/hr 9.68E-05 tpy Methylnaphthalene (2-) 1.42E-01 lb/mmscf 6.43E-04 lb/hr 1.61E-04 tpy Naphthalene 3.18E-01 lb/mmscf 1.44E-03 lb/hr 3.60E-04 tpy PAH 1.15E-01 lb/mmscf 5.21E-04 lb/hr 1.30E-04 tpy Phenol 1.02E-01 lb/mmscf 4.65E-04 lb/hr 1.16E-04 tpy Propylene Oxide Styrene 1.01E-01 lb/mmscf 4.57E-04 lb/hr 1.14E-04 tpy Tetrachloroethane (1,1,2,2-) 1.81E-01 lb/mmscf 8.23E-04 lb/hr 2.06E-04 tpy Toluene 1.74E+00 lb/mmscf 7.90E-03 lb/hr 1.98E-03 tpy Trichloroethane (1,1,2-) 1.36E-01 lb/mmscf 6.16E-04 lb/hr 1.54E-04 tpy Trimethylpentane (2,2,4-) 1.07E+00 lb/mmscf 4.84E-03 lb/hr 1.21E-03 tpy Vinyl Chloride 6.36E-02 lb/mmscf 2.89E-04 lb/hr 7.21E-05 tpy Xylenes 7.85E-01 lb/mmscf 3.56E-03 lb/hr 8.91E-04 tpy NOTES 1. Fuel higher heating value selected to correspond to AP-42 emissions factors. 2. Maximum hourly emissions based on 100% of rated capacity. 3. Vendor provided data on power output. 4. Heat rate is conservatively assumed. 5. CO2 and N2O emission factors based on 40 CFR 98, Subpart C, Table C-1 and 40 CFR 98, Subpart C, Table C-2, respectively. 6. All other emissions based on data provided in Table of AP-42 (dated 7/00). Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 11 of 26 PTE Estimates: AIM Project Revised: June 2014

80 Application Combustion Process Add-on Controls Package (Make: Model) Burner (Make: Model) Fuel Fuel Higher Heating Value (HHV) Heat Output at HHV Thermal Efficiency Operating Hours Fuel Consumption Heat Input at HHV Process Heater Conventional None Cameron: N/A Eclipse: Unknown Natural Gas 1,020 BTU/scf MMBTU/hr 65% 8,760 hrs/yr 377 scfh MMscf/yr MMBTU/hr 3,369 MMBTU/yr Uncontrolled Control Efficiency Uncontrolled Hourly Maximum Annual Pollutant NO X lb/mmscf lb/hr tpy CO lb/mmscf lb/hr tpy SO lb/mmscf lb/hr tpy PM 10/ lb/mmscf lb/hr tpy CO 2-e (6 NYCRR Part , Table 9 GWPs) 120,301 lb/mmscf lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) 120,339 lb/mmscf lb/hr tpy CO 2 120, lb/mmscf lb/hr tpy N 2 O 0.23 lb/mmscf lb/hr tpy TOC (Total) lb/mmscf lb/hr tpy Methane lb/mmscf lb/hr tpy Ethane lb/mmscf lb/hr tpy VOC (Total) lb/mmscf lb/hr tpy VOC (non-hap) lb/mmscf lb/hr tpy HAP (Total) 8.32 lb/mmscf lb/hr tpy Acetaldehyde Acrolein Benzene 9.28E-03 lb/mmscf 3.50E-06 lb/hr 1.53E-05 tpy Biphenyl Butadiene (1,3-) Carbon Tetrachloride Chlorobenzene Chloroform Dichloropropene (1,3-) Ethylbenzene Ethylene Dibromide Formaldehyde 3.31E-01 lb/mmscf 1.25E-04 lb/hr 5.47E-04 tpy Hexane (n-) 7.95E+00 lb/mmscf 3.00E-03 lb/hr 1.31E-02 tpy Methanol Methylene Chloride Methylnaphthalene (2-) 1.06E-04 lb/mmscf 4.00E-08 lb/hr 1.75E-07 tpy Naphthalene 2.69E-03 lb/mmscf 1.02E-06 lb/hr 4.45E-06 tpy PAH Phenol Propylene Oxide Styrene Tetrachloroethane (1,1,2,2-) Toluene 1.50E-02 lb/mmscf 5.66E-06 lb/hr 2.48E-05 tpy Trichloroethane (1,1,2-) Trimethylpentane (2,2,4-) Vinyl Chloride Xylenes NOTES 1. Fuel higher heating value selected to correspond to AP-42 emissions factors. 2. Maximum hourly emissions based on 105% of rated capacity. 3. Vendor provided data on: heat output and heat input. 4. CO2 and N2O emission factors based on 40 CFR 98, Subpart C, Table C-1 and 40 CFR 98, Subpart C, Table C-2, respectively. 5. NOX, CO and TOC (Total) emission factors based on vendor data. 6. SO2 and PM10/2.5 emission factors based on AP-42, Section 1.4 (Revised 3/98), Table Remaining TOC specie emission factors based on scaling of AP-42, Section 1.4 (Revised 3/98), Table using vendor HC data. EF i = (EF HC /EF TOC-AP42 ) (EF i-ap42 ) TABLE B-3a - New Gas Heater 2 Natural Gas Combustion Hourly and Annual Emission Estimates Uncontrolled Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 12 of 26 PTE Estimates: AIM Project Revised: June 2014

81 Application Combustion Process Add-on Controls Package (Make: Model) Burner (Make: Model) Fuel Fuel Higher Heating Value (HHV) Heat Output at HHV Thermal Efficiency Operating Hours Fuel Consumption Heat Input at HHV TABLE B-3b - New Gas Heater 3 Natural Gas Combustion Hourly and Annual Emission Estimates Uncontrolled Process Heater Conventional None Cameron: N/A Unknown: Unknown Natural Gas 1,020 BTU/scf MMBTU/hr 65% 8,760 hrs/yr 754 scfh MMscf/yr MMBTU/hr 6,738 MMBTU/yr Uncontrolled Pollutant Control Efficiency Uncontrolled Hourly Maximum Annual NO X lb/mmscf lb/hr tpy CO lb/mmscf lb/hr tpy SO lb/mmscf lb/hr tpy PM 10/ lb/mmscf lb/hr tpy CO 2-e (6 NYCRR Part , Table 9 GWPs) 120,301 lb/mmscf lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) 120,339 lb/mmscf lb/hr tpy CO 2 120, lb/mmscf lb/hr tpy N 2 O 0.23 lb/mmscf lb/hr tpy TOC (Total) lb/mmscf lb/hr tpy Methane lb/mmscf lb/hr tpy Ethane lb/mmscf lb/hr tpy VOC (Total) lb/mmscf lb/hr tpy VOC (non-hap) lb/mmscf lb/hr tpy HAP (Total) 8.32 lb/mmscf lb/hr tpy Acetaldehyde Acrolein Benzene 9.28E-03 lb/mmscf 7.00E-06 lb/hr 3.06E-05 tpy Biphenyl Butadiene (1,3-) Carbon Tetrachloride Chlorobenzene Chloroform Dichloropropene (1,3-) Ethylbenzene Ethylene Dibromide Formaldehyde 3.31E-01 lb/mmscf 2.50E-04 lb/hr 1.09E-03 tpy Hexane (n-) 7.95E+00 lb/mmscf 6.00E-03 lb/hr 2.63E-02 tpy Methanol Methylene Chloride Methylnaphthalene (2-) 1.06E-04 lb/mmscf 8.00E-08 lb/hr 3.50E-07 tpy Naphthalene 2.69E-03 lb/mmscf 2.03E-06 lb/hr 8.90E-06 tpy PAH Phenol Propylene Oxide Styrene Tetrachloroethane (1,1,2,2-) Toluene 1.50E-02 lb/mmscf 1.13E-05 lb/hr 4.96E-05 tpy Trichloroethane (1,1,2-) Trimethylpentane (2,2,4-) Vinyl Chloride Xylenes NOTES 1. Fuel higher heating value selected to correspond to AP-42 emissions factors. 2. Maximum hourly emissions based on 105% of rated capacity. 3. Vendor provided data on: heat output and heat input. 4. CO2 and N2O emission factors based on 40 CFR 98, Subpart C, Table C-1 and 40 CFR 98, Subpart C, Table C-2, respectively. 5. NOX, CO and TOC (Total) emission factors based on vendor data. 6. SO2 and PM10/2.5 emission factors based on AP-42, Section 1.4 (Revised 3/98), Table Remaining TOC specie emission factors based on scaling of AP-42, Section 1.4 (Revised 3/98), Table using vendor HC data. EF i = (EF HC /EF TOC-AP42 )(EF i-ap42 ) Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 13 of 26 PTE Estimates: AIM Project Revised: June 2014

82 TABLE B-4 - New Parts Washer Parts Washer Hourly and Annual Emission Estimates Solvent Solvent Density Eversol lb/gal Potential Hourly Maximum gal/hr Make-up Solvent Average gal/hr Emissions Requirement Annual gal/yr Hourly Max. Annual Speciation TOC (Total) % by weight lb/hr tpy Methane Ethane VOC (Total) % by weight lb/hr tpy HAP (Total) Benzene Ethylbenzene Hexane (n-) Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Although emissions are estimated based on the physical properties and chemical speciation of Eversol 143, other solvents may be used as long as the represented solvent density and chemical species weight percents are not exceeded. MSDS indicate that the vapor pressure at 100 F is less than 5 mmhg (0.097 psia). 2. Potential maximum annual solvent make-up is based on past experience and a safety factor. 3. Potential maximum hourly solvent make-up is the potential maximum annual solvent make-up divided by 365 day/yr. 4. Potential average hourly solvent make-up is the potential maximum annual solvent make-up divided by 8,760 hrs/yr. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 14 of 26 PTE Estimates: AIM Project Revised: June 2014

83 TABLE B-5a - New Piping Components Piping Components Hourly and Annual Emission Estimates Project-Related Increase Source Service STON-PC-NG Gas Natural Gas Minimum hours when component purged with inert gas 0 hrs/yr Component Valves Count 598 components Emission Factor 4.50E-03 kg/hr/component Connectors Count 1,202 components Emission Factor 2.00E-04 kg/hr/component Flanges Count 428 components Emission Factor 3.90E-04 kg/hr/component Open-Ended Lines Count 18 components Emission Factor 2.00E-03 kg/hr/component Pump Seals Count 0 components Emission Factor 2.40E-03 kg/hr/component Other Count 84 components Emissions Emission Factor 8.80E-03 kg/hr/component Hourly Max. Annual Speciation CO 2-e (6 NYCRR Part , Table % by weight lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs % by weight lb/hr tpy CO % by weight lb/hr tpy TOC (Total) 95.60% by weight lb/hr tpy Methane % by weight lb/hr tpy Ethane 4.962% by weight lb/hr tpy VOC (Total) 2.398% by weight lb/hr tpy HAP (Total) 0.205% by weight lb/hr tpy Benzene 0.029% by weight 2.50E-03 lb/hr 1.09E-02 tpy Ethylbenzene 0.012% by weight 9.99E-04 lb/hr 4.38E-03 tpy Hexane (n-) 0.047% by weight 4.05E-03 lb/hr 1.78E-02 tpy Methanol Naphthalene Toluene 0.037% by weight 3.12E-03 lb/hr 1.37E-02 tpy Trimethylpentane (2,2,4-) 0.000% by weight 0.00E+00 lb/hr 0.00E+00 tpy Xylenes 0.080% by weight 6.79E-03 lb/hr 2.98E-02 tpy NOTES 1. Emission factors obtained from Table 2-4 (Oil & Gas Production Operations) of Protocol for Equipment Leak Emission Estimates (EPA 453/R ). The emission factor for pumps in heavy oil service is obtained from Table Piping component counts based on design drawings for a similar compressor station. 3. The component type "Other" includes blowdown valves, relief valves, and compressor seals. 4. Weight percents based on gas analysis used to estimate gas release annual emissions (TABLE G-1b). 5. Maximum hourly emissions are based on 120% of the hourly emissions estimated in an effort to be conservative FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 15 of 26 PTE Estimates: AIM Project Revised: June 2014

84 TABLE B-5b - New Piping Components Piping Components Hourly and Annual Emission Estimates Project-Related Increase Source Service STON-PC-PL Light Oil Pipeline Liquids Minimum hours when component purged with inert gas 0 hrs/yr Component Valves Count 130 components Emission Factor 2.50E-03 kg/hr/component Connectors Count 764 components Emission Factor 2.10E-04 kg/hr/component Flanges Count 168 components Emission Factor 1.10E-04 kg/hr/component Open-Ended Lines Count 22 components Emission Factor 1.40E-03 kg/hr/component Pump Seals Count 2 components Emission Factor 1.30E-02 kg/hr/component Other Count 2 components Emissions Emission Factor 7.50E-03 kg/hr/component Hourly Max. Annual Speciation CO 2-e (6 NYCRR Part , Table % by weight lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs 0.96% by weight lb/hr tpy CO % by weight lb/hr tpy TOC (Total) 99.99% by weight lb/hr tpy Methane 0.04% by weight lb/hr tpy Ethane 0.09% by weight lb/hr tpy VOC (Total) 99.86% by weight lb/hr tpy HAP (Total) 14.54% by weight lb/hr tpy Benzene 1.44% by weight 1.83E-02 lb/hr 8.01E-02 tpy Ethylbenzene 0.48% by weight 6.04E-03 lb/hr 2.65E-02 tpy Hexane (n-) 1.69% by weight 2.15E-02 lb/hr 9.41E-02 tpy Methanol Naphthalene Toluene 4.49% by weight 5.70E-02 lb/hr 2.50E-01 tpy Trimethylpentane (2,2,4-) 0.03% by weight 3.28E-04 lb/hr 1.44E-03 tpy Xylenes 6.42% by weight 8.14E-02 lb/hr 3.57E-01 tpy NOTES 1. Emission factors obtained from Table 2-4 (Oil & Gas Production Operations) of Protocol for Equipment Leak Emission Estimates (EPA 453/R ). The emission factor for pumps in heavy oil service is obtained from Table Piping component counts based on design drawings for a similar compressor station. 3. The component type "Other" includes blowdown valves, relief valves, and compressor seals. 4. Weight percents based on composition estimate (TABLE F-1). 5. Maximum hourly emissions are based on 120% of the hourly emissions estimated in an effort to be conservative FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 16 of 26 PTE Estimates: AIM Project Revised: June 2014

85 TABLE B-5c - New Piping Components Piping Components Hourly and Annual Emission Estimates Project-Related Increase Source Service STON-PC-OIL Heavy Oil Oil Minimum hours when component purged with inert gas 0 hrs/yr Component Valves Count 118 components Emission Factor 8.40E-06 kg/hr/component Connectors Count 556 components Emission Factor 7.50E-06 kg/hr/component Flanges Count 188 components Emission Factor 3.90E-07 kg/hr/component Open-Ended Lines Count 0 components Emission Factor 1.40E-04 kg/hr/component Pump Seals Count 12 components Emission Factor 8.62E-03 kg/hr/component Other Count 4 components Emissions Emission Factor 3.20E-05 kg/hr/component Hourly Max. Annual Speciation CO 2-e (6 NYCRR Part , Table 9 GWPs) CO 2-e (40 CFR Part 98, Table A-1 GWPs) CO 2 TOC (Total) % by weight lb/hr tpy Methane Ethane VOC (Total) % by weight lb/hr tpy HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Emission factors obtained from Table 2-4 (Oil & Gas Production Operations) of Protocol for Equipment Leak Emission Estimates (EPA 453/R ). The emission factor for pumps in heavy oil service is obtained from Table Piping component counts based on design drawings for a similar compressor station. 3. The component type "Other" includes blowdown valves, relief valves, and compressor seals. 4. Weight percents based listed on MSDS. 5. Maximum hourly emissions are based on 120% of the hourly emissions estimated in an effort to be conservative FERC PDF (Unofficial) 9/29/2014 4:29:38 PM Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 17 of 26 PTE Estimates: AIM Project Revised: June 2014

86 TABLE B-6 - New Gas Release Events Gas Releases Hourly and Annual Emission Estimates Project-Related Increase Category Source Station Operations STON-GR-ST Hourly Max. Annual Gas Release 1,621 scfh 14,200,000 scf/yr 90 lb/hr 784,185 lb/yr NO X CO SO 2 PM 10/2.5 CO 2-e (6 NYCRR Part , T 1,662 lb/hr 7,279 tpy CO 2-e (40 CFR Part 98, Table A-1 1,978 lb/hr 8,663 tpy CO lb/hr tpy N 2 O TOC (Total) lb/hr tpy Methane lb/hr tpy Ethane lb/hr tpy VOC (Total) lb/hr tpy VOC (non-hap) lb/hr tpy HAP (Total) lb/hr tpy Acetaldehyde Acrolein Benzene 2.62E-02 lb/hr 1.15E-01 tpy Biphenyl Butadiene (1,3-) Carbon Tetrachloride Chlorobenzene Chloroform Dichloropropene (1,3-) Ethylbenzene 1.05E-02 lb/hr 4.59E-02 tpy Ethylene Dibromide Formaldehyde Hexane (n-) 4.25E-02 lb/hr 1.86E-01 tpy Methanol Methylene Chloride Methylnaphthalene (2-) Naphthalene PAH Phenol Propylene Oxide Styrene Tetrachloroethane (1,1,2,2-) Toluene 3.27E-02 lb/hr 1.43E-01 tpy Trichloroethane (1,1,2-) Trimethylpentane (2,2,4-) 0.00E+00 lb/hr 0.00E+00 tpy Vinyl Chloride Xylenes 7.12E-02 lb/hr 3.12E-01 tpy NOTES 1. Gas release estimates based on data for a similar compressor station 2. Gas density is 110% of the value extracted from physical property estimation spreadsheet, based on an extended gas analysis at a site in Texas. Density (TABLE G-2): lb/scf 3. Gas analysis from Thomaston, TX is used to determine gas composition. Composition is scaled to be representative of gas at a station. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 18 of 26 PTE Estimates: AIM Project Revised: June 2014

87 TABLE B-7a - Pipeline Liquids Tank Flash Analysis Maximum Hourly and Annual Emission Estimates Before and After Project Station ID STON-TK-PL1 Service Pipeline Liquids Liquids Holding Capacity 2,940 gal 2,940 gal Liquids Input Rate 11,760 gal/yr 2,940 gal/hr Flash Gas Density lb/scf lb/scf Flash Factor scf/bbl scf/bbl Flash Gas Rate 91,849 scf/yr 22,962 scfh Flash Losses 7,067 lb/yr Average Maximum 1,767 lb/hr Maximum Flash Gas % by weight lb/hr tpy % by weight 1, lb/hr CO 2-e (6 NYCRR Part , T % by weight lb/hr tpy % by weight 18,357 lb/hr CO 2-e (40 CFR Part 98, Table A % by weight lb/hr tpy CO % by weight lb/hr tpy 5.17% by weight lb/hr TOC (Total) 94.73% by weight lb/hr tpy 94.73% by weight 1, lb/hr Methane 41.36% by weight lb/hr tpy 41.36% by weight lb/hr Ethane 11.68% by weight lb/hr tpy 11.68% by weight lb/hr VOC (Total) 41.69% by weight lb/hr tpy 41.69% by weight lb/hr HAP (Total) 92.34% by weight lb/hr tpy 92.34% by weight 1, lb/hr Benzene % by weight lb/hr tpy % by weight lb/hr Ethylbenzene % by weight lb/hr tpy % by weight lb/hr Hexane (n-) % by weight lb/hr tpy % by weight lb/hr Methanol Naphthalene Toluene % by weight lb/hr tpy % by weight lb/hr Trimethylpentane (2,2,4-) % by weight lb/hr tpy % by weight lb/hr Xylenes % by weight lb/hr tpy % by weight lb/hr NOTES 1. Separator Characteristics: All flash is represented as being emitted from STON-TK-PL1, but flash may be emitted from upstream separators Orientation Height/Length Vertical Fixed Roof Tank 5.00 ft Diameter ft Capacity (physical) 2,938 gal Capacity (liquid) 2,940 gal 100% of physical capacity 2. Liquid input rates: a. maximum hourly based on operator experience 2,940 gal b. maximum annual based on operating experience and safety factor; and 11,760 gal c. average hourly is just the maximum annual divided by 8,760 hrs/yr 3. Flash gas density is 110% of the value extracted from TABLE E-3b Density (TABLE E-3b): lb/scf Safety Factor: 110% 4. Flash factor extracted from TABLE E Speciated emissions vapor weight percentages extracted from TABLE E-3b Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 19 of 26 PTE Estimates: AIM Project Revised: June 2014

88 Source Service Capacity Temperature of Stored Liquid Vapor Pressure Pumping Rate Throughput Standing Losses Working Losses TABLE B-7b - Pipeline Liquids Tank Volatile Organic Liquids Storage Tanks Hourly and Annual Emission Estimates Standing & Working Losses Before and After Project STON-TK-PL1 Pipeline Liquids 2,940 gal 2,940 gal F F psia psia 150 gal/min 150 gal/min 4.00 turnover/yr 11,760 gal/yr 2,940 gal/hr July 744 hrs/month lbs/month lb/yr lb/hr 8.00E-03 lb/gal 1.01E-02 lb/gal lb/yr Average Maximum lb/hr Maximum Stand lb/hr tpy lb/hr Residual Liquid Work % by weight lb/hr tpy % by weight lb/hr Total lb/hr tpy lb/hr CO 2-e (6 NYCRR Part , Table 9 G % by weight lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) % by weight lb/hr tpy % by weight 1,608 lb/hr CO % by weight lb/hr tpy 7.83% by weight lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane % by weight lb/hr tpy % by weight lb/hr Ethane 35.39% by weight lb/hr tpy 35.39% by weight lb/hr VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) 6.23% by weight lb/hr tpy 6.23% by weight lb/hr Benzene % by weight 1.28E-03 lb/hr 5.62E-03 tpy % by weight 4.49E-01 lb/hr Ethylbenzene % by weight 4.06E-05 lb/hr 1.78E-04 tpy % by weight 1.42E-02 lb/hr Hexane (n-) % by weight 2.46E-03 lb/hr 1.08E-02 tpy % by weight 8.60E-01 lb/hr Methanol Naphthalene Toluene % by weight 1.16E-03 lb/hr 5.10E-03 tpy % by weight 4.07E-01 lb/hr Trimethylpentane (2,2,4-) % by weight 1.18E-05 lb/hr 5.18E-05 tpy % by weight 4.14E-03 lb/hr Xylenes % by weight 3.47E-04 lb/hr 1.52E-03 tpy % by weight 1.21E-01 lb/hr NOTES 1. Tank Characteristics: TANKS 4.09d Orientation Height/Length Vertical Fixed Roof Tank 5.00 ft Above Ground? Shell/Roof Color Yes Gray/Medium or less solar Diameter ft Shell Condition Good absorptance Capacity (estimated) 2,938 gal Vacuum Setting psig Capacity (nominal) 2,940 gal Pressure Setting 0.03 psig 2. Stored Liquid Characteristics: Basis USEPA TANKS 4.09d MET Station: Laguardia AP, New York Material Pipeline Liquids (RVP 10) Selection based on VOC vapor pressure (see Table E-1) Liquid Molecular Weight lb/lb-mol Vapor Molecular Weight lb/lb-mol Monthly Data Days Vapor Pressure Liquid Surface Temperature TANKS Output TANKS avg max avg max standing working Flow January ,940 February ,940 March ,940 April ,940 May ,940 June ,940 July ,940 August ,940 September ,940 October ,940 November ,940 December ,940 ALL , Emission Estimate Basis: USEPA TANKS 4.09d & TCEQ RG-166/01 4. Speciation of emissions is based on vapor weight percentages in TABLE F-1 normalized on VOC to assure methodology is conservative Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 20 of 26 PTE Estimates: AIM Project Revised: June 2014

89 TABLE B-7c - Lubricating Oil Tank 1 Volatile Organic Liquids Storage Tanks Hourly and Annual Emission Estimates Standing & Working Losses Before and After Project Source Service Capacity Temperature of Stored Liquid Vapor Pressure Pumping Rate Throughput STON-TK-OIL1 Lubricating Oil 4,200 gal 4,200 gal F F psia psia 150 gal/min 150 gal/min turnover/yr 1,533,000 gal/yr 4,200 gal/hr Standing Losses July 744 hrs/month lbs/month lb/yr lb/hr Working Losses 2.32E-05 lb/gal 3.28E-05 lb/gal lb/yr Average Maximum lb/hr Maximum Stand lb/hr tpy lb/hr Liquid Work % by weight lb/hr tpy % by weight lb/hr Total lb/hr tpy lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane Ethane VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Tank Characteristics: TANKS 4.09d Orientation Height/Length Horizontal Tank ft ft Above Ground? Shell/Roof Color Yes Gray/Medium or less solar Diameter 6.00 ft Shell Condition Good absorptance Capacity (estimated) 4,221 gal Vacuum Setting psig Capacity (nominal) 4,200 gal Pressure Setting 0.03 psig 2. Stored Liquid Characteristics: Basis USEPA TANKS 4.09d MET Station: Laguardia AP, New York Material Distillate fuel oil no. 2 Selected purely for a worst-case scenario. Liquid Molecular Weight lb/lb-mol Vapor Molecular Weight lb/lb-mol Monthly Data Days Vapor Pressure Liquid Surface Temperature TANKS Output TANKS avg max avg max standing working Flow January ,200 February ,200 March ,200 April ,200 May ,200 June ,200 July ,200 August ,200 September ,200 October ,200 November ,200 December ,200 ALL , Emission Estimate Basis: USEPA TANKS 4.09d & TCEQ RG-166/01 4. There is no basis for speciation of emissions. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 21 of 26 PTE Estimates: AIM Project Revised: June 2014

90 TABLE B-7d - Lubricating Oil Tank 2 Volatile Organic Liquids Storage Tanks Hourly and Annual Emission Estimates Standing & Working Losses Before and After Project Source Service Capacity Temperature of Stored Liquid Vapor Pressure Pumping Rate Throughput STON-TK-OIL2 Lubricating Oil 3,800 gal 3,800 gal F F psia psia 150 gal/min 150 gal/min turnover/yr 1,387,000 gal/yr 3,800 gal/hr Standing Losses July 744 hrs/month lbs/month lb/yr lb/hr Working Losses 2.32E-05 lb/gal 3.28E-05 lb/gal lb/yr Average Maximum lb/hr Maximum Stand lb/hr tpy lb/hr Liquid Work % by weight lb/hr tpy % by weight lb/hr Total lb/hr tpy lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane Ethane VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Tank Characteristics: TANKS 4.09d Orientation Height/Length Horizontal Tank ft Above Ground? Shell/Roof Color Yes Gray/Medium or less solar Diameter 6.00 ft Shell Condition Good absorptance Capacity (estimated) 3,807 gal Vacuum Setting psig Capacity (nominal) 3,800 gal Pressure Setting 0.03 psig 2. Stored Liquid Characteristics: Basis USEPA TANKS 4.09d MET Station: Laguardia AP, New York Material Distillate fuel oil no. 2 Selected purely for a worst-case scenario. Liquid Molecular Weight lb/lb-mol Vapor Molecular Weight lb/lb-mol Monthly Data Days Vapor Pressure Liquid Surface Temperature TANKS Output TANKS avg max avg max standing working Flow January ,800 February ,800 March ,800 April ,800 May ,800 June ,800 July ,800 August ,800 September ,800 October ,800 November ,800 December ,800 ALL , Emission Estimate Basis: USEPA TANKS 4.09d & TCEQ RG-166/01 4. There is no basis for speciation of emissions. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 22 of 26 PTE Estimates: AIM Project Revised: June 2014

91 TABLE B-7e - Lubricating Oil Tank 3 Volatile Organic Liquids Storage Tanks Hourly and Annual Emission Estimates Standing & Working Losses Before and After Project Source Service Capacity Temperature of Stored Liquid Vapor Pressure Pumping Rate Throughput STON-TK-OIL3 Lubricating Oil 1,080 gal 1,080 gal F F psia psia 150 gal/min 150 gal/min turnover/yr 394,200 gal/yr 1,080 gal/hr Standing Losses July 744 hrs/month lbs/month lb/yr lb/hr Working Losses 2.32E-05 lb/gal 3.28E-05 lb/gal lb/yr Average Maximum lb/hr Maximum Stand lb/hr tpy lb/hr Liquid Work % by weight lb/hr tpy % by weight lb/hr Total lb/hr tpy lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane Ethane VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Tank Characteristics: TANKS 4.09d Orientation Height/Length Horizontal Tank ft ft Above Ground? Shell/Roof Color Yes Gray/Medium or less solar Diameter 4.00 ft Shell Condition Good absorptance Capacity (estimated) 1,082 gal Vacuum Setting psig Capacity (nominal) 1,080 gal Pressure Setting 0.03 psig 2. Stored Liquid Characteristics: Basis USEPA TANKS 4.09d MET Station: Laguardia AP, New York Material Distillate fuel oil no. 2 Selected purely for a worst-case scenario. Liquid Molecular Weight lb/lb-mol Vapor Molecular Weight lb/lb-mol Monthly Data Days Vapor Pressure Liquid Surface Temperature TANKS Output TANKS avg max avg max standing working Flow January ,080 February ,080 March ,080 April ,080 May ,080 June ,080 July ,080 August ,080 September ,080 October ,080 November ,080 December ,080 ALL , Emission Estimate Basis: USEPA TANKS 4.09d & TCEQ RG-166/01 4. There is no basis for speciation of emissions. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 23 of 26 PTE Estimates: AIM Project Revised: June 2014

92 TABLE B-7f - Oily Water Tank Volatile Organic Liquids Storage Tanks Hourly and Annual Emission Estimates Standing & Working Losses Before and After Project Source Service Capacity Temperature of Stored Liquid Vapor Pressure Pumping Rate Throughput Standing Losses Working Losses STON-TK-OW1 Oily Water (Stormwater) 1,300 gal 1,300 gal F F psia psia 150 gal/min 150 gal/min turnover/yr 474,500 gal/yr 1,300 gal/hr July 744 hrs/month lbs/month lb/yr lb/hr 2.32E-05 lb/gal 3.28E-05 lb/gal lb/yr Average Maximum lb/hr Maximum Stand lb/hr tpy lb/hr Liquid Work % by weight lb/hr tpy % by weight lb/hr Total lb/hr tpy lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane Ethane VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Tank Characteristics: TANKS 4.09d Orientation Height/Length Horizontal Tank ft ft Above Ground? Shell/Roof Color Yes Gray/Medium or less solar Diameter 4.00 ft Shell Condition Good absorptance Capacity (estimated) 1,332 gal Vacuum Setting psig Capacity (nominal) 1,300 gal Pressure Setting 0.03 psig 2. Stored Liquid Characteristics: Basis USEPA TANKS 4.09d MET Station: Laguardia AP, New York Material Distillate fuel oil no. 2 Selected purely for a worst-case scenario. Liquid Molecular Weight lb/lb-mol Vapor Molecular Weight lb/lb-mol Monthly Data Days Vapor Pressure Liquid Surface Temperature TANKS Output TANKS avg max avg max standing working Flow January ,300 February ,300 March ,300 April ,300 May ,300 June ,300 July ,300 August ,300 September ,300 October ,300 November ,300 December ,300 ALL , Emission Estimate Basis: USEPA TANKS 4.09d & TCEQ RG-166/01 4. There is no basis for speciation of emissions. Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 24 of 26 PTE Estimates: AIM Project Revised: June 2014

93 TABLE B-8a - Pipeline Liquids Truck Loading Volatile Organic Liquids Loading (Tanker Trucks) Hourly and Annual Emission Estimates Before and After Project Source STON-TL-PL Supply Vessel STON-TK-PL1 Pipeline Liquids 2,940 gal 2,940 gal Tanker Truck Service Loading Method Saturation Factor Dedicated Normal Submerged 0.60 n.d. Dedicated Normal Submerged 0.60 n.d. Vapor Molecular Weight lb/lb-mol lb/lb-mol Bulk Liquid Temperature F F R R Vapor Pressure psia psia Loading Loss Factor lb/kgal lb/kgal Pumping Rate 150 gpm Throughput 4.00 turnover/yr 11,760 gal/yr 2,940 gal/hr Loading Losses lb/yr Average Maximum lb/hr Maximum Residual Liquid % by weight lb/hr tpy % by weight lb/hr CO 2-e (6 NYCRR Part , Table 9 G % by weight lb/hr tpy CO 2-e (40 CFR Part 98, Table A-1 GWPs) % by weight lb/hr tpy % by weight 1, lb/hr CO % by weight lb/hr tpy 7.83% by weight lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane % by weight lb/hr tpy % by weight lb/hr Ethane 35.39% by weight lb/hr tpy 35.39% by weight lb/hr VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) 6.23% by weight lb/hr tpy 6.23% by weight lb/hr Benzene % by weight 9.72E-05 lb/hr 4.26E-04 tpy % by weight 3.14E-01 lb/hr Ethylbenzene % by weight 3.08E-06 lb/hr 1.35E-05 tpy % by weight 9.93E-03 lb/hr Hexane (n-) % by weight 1.86E-04 lb/hr 8.16E-04 tpy % by weight 6.01E-01 lb/hr Methanol Naphthalene Toluene % by weight 8.82E-05 lb/hr 3.86E-04 tpy % by weight 2.85E-01 lb/hr Trimethylpentane (2,2,4-) % by weight 8.96E-07 lb/hr 3.93E-06 tpy % by weight 2.89E-03 lb/hr Xylenes % by weight 2.63E-05 lb/hr 1.15E-04 tpy % by weight 8.48E-02 lb/hr NOTES 1. Emissions calculated using methods provided in USEPA, AP-42 Section 5.2 dated 1/95. L L = 12.46[(S)M V P/T] 2. Physical property, throughput and speciation data based data from supply vessel emission calculation spreadsheet Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 25 of 26 PTE Estimates: AIM Project Revised: June 2014

94 TABLE B-8b - Lubricating Oil Truck Loading Volatile Organic Liquids Loading (Tanker Trucks) Hourly and Annual Emission Estimates Before and After Project Source STON-TL-OIL Supply Vessel STON-TK-OIL3 Lubricating Oil 1,080 gal 1,080 gal Tanker Truck Service Loading Method Saturation Factor Dedicated Normal Splash 1.45 n.d. Dedicated Normal Splash 1.45 n.d. Vapor Molecular Weight lb/lb-mol lb/lb-mol Bulk Liquid Temperature F F R R Vapor Pressure psia psia Loading Loss Factor lb/kgal lb/kgal Pumping Rate 150 gpm Throughput turnover/yr 12,960 gal/yr 1,080 gal/hr Loading Losses lb/yr Average Maximum lb/hr Maximum Residual Liquid % by weight lb/hr tpy % by weight lb/hr TOC (Total) % by weight lb/hr tpy % by weight lb/hr Methane Ethane VOC (Total) % by weight lb/hr tpy % by weight lb/hr HAP (Total) Benzene Ethylbenzene Hexane (n-) Methanol Naphthalene Toluene Trimethylpentane (2,2,4-) Xylenes NOTES 1. Emissions calculated using methods provided in USEPA, AP-42 Section 5.2 dated 1/95. L L = 12.46[(S)M V P/T] 2. Physical property, throughput and speciation data based data from supply vessel emission calculation spreadsheet Algonquin Gas Transmission, LLC Stony Point Compressor Station Page 26 of 26 PTE Estimates: AIM Project Revised: June 2014

95 SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 1 HP=17612, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 0.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 1 Fuel: SD NATURAL GAS Water Injection: NO Customer: Spectra Energy Inquiry Number:

96 Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP=17612, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 0.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 2 HP=17075, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 20.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) =

97 N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 2 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP=17075, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 20.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel,

98 and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 3 HP=16376, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 40.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O2

99 VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 3 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP=16376, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 40.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 4

100 HP=15442, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 60.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 4 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point:

101 HP=15442, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 60.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 5 HP=14336, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 80.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg

102 NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 5 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP=14336, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature= 80.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address

103 turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 6 HP=13105, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature=100.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL)

104 SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 6 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP=13105, %Full Load=100.0, Elev= 0ft, %RH= 60.0, Temperature=100.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED DATE RUN: 24-May-12 ENGINE PERFORMANCE CODE REV RUN BY: Briz B Garcia CUSTOMER: Spectra Energy JOB ID: MARS S CS/MD STANDARD GAS TMG-2S REV. 1.0 DATA FOR NOMINAL PERFORMANCE

105 Fuel Type SD NATURAL GAS Elevation feet 0 Inlet Loss in H2O 4 Exhaust Loss in H2O 4 Accessory on GP Shaft HP 58 Engine Inlet Temp. deg F Relative Humidity % Inlet Loss HP Exhaust Loss HP Driven Equipment Speed RPM Optimum Equipment SpeedRPM Gas Generator Speed RPM Specified Load HP FULL FULL FULL FULL FULL FULL Net Output Power HP Fuel Flow mmbtu/hr Heat Rate Btu/HP-hr Therm Eff % Inlet Air Flow lbm/hr Engine Exhaust Flow lbm/hr PCD psig Compensated PTIT deg F PT Exit Temperature deg F Exhaust Temperature deg F FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) SG (Btu/Scf) Methane (CH4) Ethane (C2H6) 4.16 Propane (C3H8) 0.84 N-Butane (C4H10) 0.18 N-Pentane (C5H12) 0.04 Hexane (C6H14) 0.04 Carbon Dioxide (CO2) 0.44 Hydrogen Sulfide (H2S) Nitrogen (N2) 1.51

106 SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 1 HP= 8806, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 0.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 1 Fuel: SD NATURAL GAS Water Injection: NO Customer: Spectra Energy Inquiry Number:

107 Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP= 8806, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 0.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 2 HP= 8538, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 20.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) =

108 N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 2 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP= 8538, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 20.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel,

109 and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 3 HP= 8188, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 40.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O2

110 VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 3 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP= 8188, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 40.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 4

111 HP= 7721, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 60.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 4 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point:

112 HP= 7721, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 60.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 5 HP= 7168, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 80.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg

113 NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL) SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 5 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP= 7168, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature= 80.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address

114 turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia --- SUMMARY OF ENGINE EXHAUST ANALYSIS --- POINT NUMBER 6 HP= 6552, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature=100.0F GENERAL INPUT SPECIFICATIONS ENGINE FUEL: SD NATURAL GAS in Hg AMBIENT PRESSURE 60.0 percent RELATIVE HUMIDITY SP. HUMIDITY (LBM H2O/LBM DRY AIR) FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) = SG = (Btu/Scf) = Methane (CH4) = Ethane (C2H6) = Propane (C3H8) = N-Butane (C4H10) = N-Pentane (C5H12) = Hexane (C6H14) = Carbon Dioxide (CO2) = Hydrogen Sulfide (H2S) = Nitrogen (N2) = STANDARD CONDITIONS FOR GAS VOLUMES: Temperature: 60 deg F Pressure: in Hg NORMAL CONDITIONS FOR GAS VOLUMES: Temperature: 32 deg F Pressure: in Hg GENERAL OUTPUT DATA EXHAUST GAS ANALYSIS lbm/hr FUEL FLOW Scfm FUEL FLOW Btu/lbm LOWER HEATING VALUE 939. Btu/Scf LOWER HEATING VALUE Scfm EXHAUST 14.7 PSIA & 60F Acfm ACTUAL EXHAUST FLOW CFm lbm/hr EXHAUST GAS FLOW MOLECULAR WEIGHT OF EXHAUST GAS AIR/FUEL RATIO ARGON CO2 H2O N2 O VOLUME PERCENT WET VOLUME PERCENT DRY lbm/hr g/(g FUEL)

115 SOLAR TURBINES INCORPORATED ENGINE PERFORMANCE CODE REV CUSTOMER: Spectra Energy JOB ID: DATE RUN: 24-May-12 RUN BY: Briz B Garcia NEW EQUIPMENT PREDICTED EMISSION PERFORMANCE DATA FOR POINT NUMBER 6 Fuel: SD NATURAL GAS Customer: Spectra Energy Water Injection: NO Inquiry Number: Model: MARS S CS/MD STANDARD GAS Emissions Data: REV. 1.0 The following predicted emissions performance is based on the following specific single point: HP= 6552, %Full Load= 50.0, Elev= 0ft, %RH= 60.0, Temperature=100.0F NOX CO UHC PPMvd at 15% O ton/yr lbm/mmbtu (Fuel LHV) lbm/(mw-hr) (gas turbine shaft pwr) lbm/hr NOTES: 1. For short-term emission limits such as lbs/hr., Solar recommends using "worst case" anticipated operating conditions specific to the application and the site conditions. Worst case for one pollutant is not necessarily the same for another. 2. Solar's typical SoLoNOx warranty, for ppm values, is available for greater than 0 deg F, and between 50% and 100% load for gas fuel, and between 65% and 100% load for liquid fuel (except for the Centaur 40). An emission warranty for non-solonox equipment is available for greater than 0 deg F and between 80% and 100% load. 3. Fuel must meet Solar standard fuel specification ES Emissions are based on the attached fuel composition, or, San Diego natural gas or equivalent. 4. If needed, Solar can provide Product Information Letters to address turbine operation outside typical warranty ranges, as well as nonwarranted emissions of SO2, PM10/2.5, VOC, and formaldehyde. 5. Solar can provide factory testing in San Diego to ensure the actual unit(s) meet the above values within the tolerances quoted. Pricing and schedule impact will be provided upon request. 6. Any emissions warranty is applicable only for steady-state conditions and does not apply during start-up, shut-down, malfunction, or transient event. SOLAR TURBINES INCORPORATED DATE RUN: 24-May-12 ENGINE PERFORMANCE CODE REV RUN BY: Briz B Garcia CUSTOMER: Spectra Energy JOB ID: MARS S CS/MD STANDARD GAS TMG-2S REV. 1.0 DATA FOR NOMINAL PERFORMANCE

116 Fuel Type SD NATURAL GAS Elevation feet 0 Inlet Loss in H2O 4 Exhaust Loss in H2O 4 Accessory on GP Shaft HP 58 Engine Inlet Temp. deg F Relative Humidity % Inlet Loss HP Exhaust Loss HP Driven Equipment Speed RPM Optimum Equipment SpeedRPM Gas Generator Speed % Gas Generator Speed RPM Specified Load HP 50.00% 50.00% 50.00% 50.00% 50.00% 50.00% Net Output Power HP Fuel Flow mmbtu/hr Heat Rate Btu/HP-hr Therm Eff % Inlet Air Flow lbm/hr Engine Exhaust Flow lbm/hr PCD psig Compensated PTIT deg F PT Exit Temperature deg F Exhaust Temperature deg F FUEL GAS COMPOSITION (VOLUME PERCENT) LHV (Btu/Scf) SG (Btu/Scf) Methane (CH4) Ethane (C2H6) 4.16 Propane (C3H8) 0.84 N-Butane (C4H10) 0.18 N-Pentane (C5H12) 0.04 Hexane (C6H14) 0.04 Carbon Dioxide (CO2) 0.44 Hydrogen Sulfide (H2S) Nitrogen (N2) 1.51

117 Solar Turbines Incorporated 9330 Sky Park Court SP4-B San Diego, CA Tel: (858) Submitted Electronically April 10, 2014 Attn: Owen McManus Principal Engineer Environmental Compliance Spectra Energy Transmission LLC RE: Stony Point Compressor Station Mars S NOx Emissions Signature Based on site conditions and site fuel, Solar Turbines has offered Spectra Energy a 9 ppm NOx warranty on the Mars S at the Stony Point Compressor Station. The NOx warranty is valid from % load and at ambient temperatures greater than 0ºF. Please call me at if you have any questions. Sincerely, Leslie Witherspoon Manager, Environmental Programs Solar Turbines Incorporated witherspoon_leslie_h@solarturbines.com cc: Roy Barnes, Spectra Energy, RABarnes@spectraenergy.com Kenneth Shutter, Spectra Energy, KRShutter@spectraenergy.com Tom Cleeland, Solar Turbines, cleeland_thomas_w@solarturbines.com C:\LESLIE\CUST_QS AND PROJECTS\2013\# AIM EXPANSION SPECTRA\STONY POINT NOX LETTER.DOC

118 Solar Turbines Incorporated 9330 Sky Park Court San Diego, CA Tel: (858) Submitted Electronically May 9, 2014 Attn: RE: Owen McManus Particulate Matter Emissions Estimates Solar's standard warranty level for PM10/2.5 is lb/mmbtu (HHV). The lb/mmbtu (HHV) warrantable emission factor is conservative. It based on historical source test data collected from our customers. It is intended to cover our entire product line and is valid from % load and at ambient temperatures greater than 0ºF. The level allows margin for customers who may not hire an experienced source testing firm and for those who may not follow the recommendations that help obtain the best PM10/2.5 test results (see Testing Recommendations). Recent customer source testing has shown that the AP-42 emission factors for natural gas combustion turbines are achievable in the field - when the test method recommendations are followed. Because particulate matter emissions levels are highly dependent on the test firm and have very little to do with the turbine, Solar does not warrant AP-42 levels while recognizing the levels can be measured in the field. Customers are welcome to estimate particulate matter using Solar's warranty level, AP-42, or another emission factor that they feel is a representative value for their site. For the proposed CT projects, Spectra would like to estimate the PM10/2.5 emissions using AP-42. The CTDEP has pushed back noting that Spectra should use the OEM value. A summary of recent source testing data is summarized in Table 1. The average emission rate is lb/mmbtu (HHV). The 95% Upper Confidence of Mean is lb/mmbtu (HHV). Based on the 95% Upper Confidence of Mean, using AP-42 is a reasonable and likely field attainable estimate for PM10/2.5 emissions for the Taurus 60 and Mars 100 currently proposed for Chaplain and Cromwell, respectively. While Solar does not warranty AP-42 levels, evaluation of our customer source test data indicates that if proper testing procedures are followed, the AP-42 emission factor is a representative estimate of PM10/2.5 emissions. Please call me at if you have any questions. Sincerely, Leslie Witherspoon Manager, Environmental Programs Solar Turbines Incorporated Witherspoon_leslie_h@solarturbines.com C:\LESLIE\CUST_QS AND PROJECTS\2013\# AIM EXPANSION SPECTRA\PARTICULATE MATTER LETTER.DOC

119 Table 1. PM10/2.5 Stack Test Data Since 1/1/2004 (Turbine Only, Duct Burners and HRSG not included). Test PM10/2.5 Reference # lb/mmbtu (HHV) NG-16 Test NG-16 Test NG-16 Test NG-17 Test NG-17 Test NG-17 Test NG-18 Test NG-18 Test NG-18 Test NG-26 Test NG-41 Test NG-41 Test NG-41 Test NG-42 Test NG-42 Test NG-42 Test NG-44 Test NG-44 Test NG-44 Test NG-46 Test NG-46 Test NG-46 Test NG-50 Test NG-52 Test NG-52 Test NG-52 Test NG-53 Test NG-53 Test NG-53 Test NG-55 Test NG-55 Test NG-55 Test NG-57 Test NG-57 Test NG-57 Test max min average stdev % Confidence Interval (upper)

120 TEST METHOD RECOMMENDATIONS Solar recommends that EPA Methods 201/201A¹ be used to measure the front half. Front half represents filterable particulate matter. EPA Method 202² (with nitrogen purge and field blanks) should be used to measure the back half. Back half measurements represent the condensable portion of particulate matter. EPA Method 5³, which measures the front and back halves may be substituted (e.g. where exhaust temperatures do not allow the use of Method 202). Testing should include three test runs of 4 hours each. Solar recommends using the aforementioned test methods until more representative test methods are developed and made commercially available.

121 GE Energy Gas Engines Waukesha * gas engine VGF * Series Enginator * generating system VGF24GL/GLD kwe GE s Waukesha VGF generator sets offer a compact, fuelfl exible package delivering exceptional performance in prime power, cogeneration, peak shaving and stand-by power applications. The VGF24 generator set is designed for standby and continuous power applications and is rated at kwe at 50 Hz (1500 rpm) and kwe at 60 Hz (1800 rpm). technical data Waukesha engine H24GL/GLD Cylinders Inline 8 Piston displacement 1462 cu. in. (24 L) Compression ratio 11:1 Bore & stroke 5.98 x 6.5 (152 x 165 mm) Jacket water system capacity 20 gal. (75 L) Lube oil capacity 56 gal. (212 L) Starting system 24V DC electric Dimensions l x w x h inch (mm) Heat exchanger 168 (4270) x 54 (1370) x 79 (2000) Water cooler 143 (3630) x 54 (1370) x 79 (2000) Radiator 183 (4650) x 88 (2240) x 112 (2840) Weights lb (kg) Heat exchanger (5900) Water connection (5540) Radiator (6680) *Trademark of General Electric Company

122 performance data Intercooler Water Temperature 130 F (54 C) Emissions Heat Balance Intake/Exhaust System 60 Hz 1800 RPM Continuous Power 50 Hz 1500 RPM 60 Hz 1800 RPM Standby Power 50 Hz 1500 RPM Power kw (heat exchanger/water connection cooling) 415** 340** Power kw (radiator cooling) 390** 325** BSFC (LHV) Btu/bhp-hr (kj/kwh) 7016 (9923) 6817 (9642) 6967 (9854) 6774 (10193) Fuel Consumption Btu/hr x 1000 (kw) 4104 (1203) 3340 (979) 4285 (1256) 3489 (1035) NOx g/bhp-hr (mg/nm 5% O 2 ) 2.00 (822) 2.50 (1004) 2.00 (822) 2.50 (1004) CO g/bhp-hr (mg/nm 5% O 2 ) 1.30 (541) 1.30 (519) 1.30 (541) 1.30 (519) NMHC g/bhp-hr (mg/nm 5% 0 2 ) 0.26 (105) 0.30 (122) 0.26 (105) 0.30 (122) THC g/bhp-hr (mg/nm 5% O 2 ) 1.60 (650) 2.00 (806) 1.60 (650) 2.00 (806) Heat to Jacket Water Btu/hr x 1000 (kw) 1043 (306) 886 (260) 1077 (316) 912 (267) Heat to Lube Oil Btu/hr x 1000 (kw) 129 (38) 93 (27) 131 (38) 94 (28) Heat to Intercooler Btu/hr x 1000 (kw) 256 (75) 174 (51) 273 (80) 185 (54) Heat to Radiation Btu/hr x 1000 (kw) 89 (26) 83 (24) 88 (26) 73 (21) Total Exhaust Heat Btu/hr x 1000 (kw) 1177 (345) 921 (270) 1196 (351) 942 (276) Induction Air Flow scfm (Nm 3 /hr) 1238 (1903) 1008 (1549) 1215 (1865) 990 (1520) Exhaust Flow lb/hr (kg/hr) 5398(2449) 4393(1992) 5540(2513) 4520(2049) Exhaust Temperature F ( C) 842 (450) 808 (431) 844 (451) 810 (432) Radiator Air Flow scfm (m3/min) (radiator cooling) (1532) (1294) (1532) (1294) **Requires option code Rating Standard: The Waukesha Enginator ratings are based on ISO 3046/ with an engine mechanical efficiency of 90% and auxiliary water temperature Tcra as specifi ed limited to ±10 F (±5 C). Ratings also valid for ISO 8528 and DIN 6271, BS 5514 standard atmospheric conditions. Continuous Power Rating: The highest electrical power output of the Enginator available for an unlimited number of hours per year, less maintenance. It is permissable to operate the Enginator with up to 10% overload for two hours in each 24 hour period. Standby Power Rating: This rating applies to those systems used as a secondary source of electrical power. This rating is the electrical power output of the Enginator (no overload) 24 hours a day, for the duration of a power source outage. All data according to full load and subject to technical development and modifi cation. Consult your local GE Energy s representative for system application assistance. The manufacturer reserves the right to change or modify without notice, the design or equipment specifi cations as herein set forth without incurring any obligation either with respect to equipment previously sold or in the process of construction except where otherwise specifi cally guaranteed by the manufacturer. GE Energy 1101 West Saint Paul Ave. Waukesha, WI P: F: Visit us online at: General Electric Company All Rights Reserved GEA-19075

123 GE Energy Gas Engines Waukesha * gas engines VGF * H24GL BHP ( kwb) The VGF series of high-speed engines are built with the durability expected from a medium-speed engine. This series of engines is designed for a wide range of stationary, spark-ignited, gaseous fuel applications and has a high power-to-weight ratio operating up to 1800 RPM. The VGF Series simplifi es maintenance procedures. The engine design allows easy access to the oil pump, main bearings and rod bearings without the need to lower the oil pan. Commonality of parts between VGF models reduces the amount of inventory needed for servicing a fl eet. Standard design features, such as independent heads, simplify maintenance work. technical data Cylinders Inline 8 Piston displacement 1462 cu. in. (24 L) Compression ratio LCR 8.7:1, HCR 11:1 Bore & stroke 5.98 x 6.5 (152 x 165 mm) Jacket water system capacity 20 gal. (75 L) Lube oil capacity 56 gal. (212 L) Fuel Pressure Range psi ( bar) Starting system 150 psi max. air/gas 24V DC electric Cooling Water Flow at 1500 rpm 1800 rpm Jacket Water gpm (l/m) 103 (390) 130 (492) Aux. Water gpm (l/m) 25 (95) 35 (133) Dimensions l x w x h inch (mm) 96.5 (2451) x 50 (1264) x 68 (1727) Weights lb (kg) 7500 (3400) *Trademark of General Electric Company

124 performance data Intercooler Water Temperature 130 F (54 C) 1800 RPM 1500 RPM Emissions Heat Balance Intake/ Exhaust System Power bhp (kwb) 530 (395) 445 (330) BSFC (LHV) Btu/bhp-hr (kj/kwh) 7120 (10082) 6902 (9826) Fuel Consumption Btu/hr x 1000 (kw) 3774 (1106) 3071 (901) NOx g/bhp-hr (mg/nm 5% O 2 ) 2.00 (810) 2.4 (981) CO g/bhp-hr (mg/nm 5% O 2 ) 1.30(535) 1.4(564) NMHC g/bhp-hr (mg/nm 5% 0 2 ) 0.27 (108) 0.31 (125) THC g/bhp-hr (mg/nm 5% O 2 ) 1.7 (683) 2.2 (836) Heat to Jacket Water Btu/hr x 1000 (kw) 980 (287) 833 (244) Heat to Lube Oil Btu/hr x 1000 (kw) 126 (37) 91 (27) Heat to Intercooler Btu/hr x 1000 (kw) 226 (66) 153 (45) Heat to Radiation Btu/hr x 1000 (kw) 89 (26) 83 (24) Total Exhaust Heat Btu/hr x 1000 (kw) 1077 (316) 839 (246) Induction Air Flow scfm (Nm 3 /hr) 1139 (1749) 927 (1425) Exhaust Flow lb/hr (kg/hr) 4964 (2251) 4041 (1834) Exhaust Temperature F ( C) 838 (448) 804 (429) All data according to full load and subject to technical development and modifi cation. Consult your local GE Energy s representative for system application assistance. The manufacturer reserves the right to change or modify without notice, the design or equipment specifi cations as herein set forth without incurring any obligation either with respect to equipment previously sold or in the process of construction except where otherwise specifi cally guaranteed by the manufacturer. GE Energy 1101 West Saint Paul Ave. Waukesha, WI P: F: Visit us online at: General Electric Company All Rights Reserved GEA-19031

125 APPENDIX C: NYSDEC AIR PERMIT APPLICATION FORM Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

126

127 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section II - Identification Information Project Description (continuation) 12/21/01 CONTINUATION SHEET OF

128 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section III - Facility Information Classification Hospital Residential Educational/Institutional Commercial Industrial Utility Affected States (Title V Only) Vermont Massachusetts Rhode Island Pennsylvania Tribal Land: New Hampshire Connecticut New Jersey Ohio Tribal Land: SIC Codes Facility Description Continuation Sheet(s) Compliance Statements (Title V Only) I certify that as of the date of this application the facility is in compliance with all applicable requirements: YES NO If one or more emission units at the facility are not in compliance with all applicable requirements at the time of signing this application (the NO box must be checked), the noncomplying units must be identified in the Compliance Plan block on page 8 of this form along with the compliance plan information required. For all emission units at this facility that are operating in compliance with all applicable requirements complete the following: This facility will continue to be operated and maintained in such a manner as to assure compliance for the duration of the permit, except those units referenced in the compliance plan portion of Section IV of this application. For all emission units, subject to any applicable requirements that will become effective during the term of the permit, this facility will meet all such requirements on a timely basis. Compliance certification reports will be submitted at least once a year. Each report will certify compliance status with respect to each requirement, and the method used to determine the status. Facility Applicable Federal Requirements Continuation Sheet(s) Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Facility State Only Requirements Continuation Sheet(s) Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause 12/21/01 PAGE 2

129 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section III - Facility Information Facility Applicable Federal Requirements (continuation) Title Type Part Sub Part Section Sub Paragraph Sub Claus Sub 12/21/01 CONTINUATION SHEET OF

130 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section III - Facility Information Facility Description (continuation) 12/21/01 CONTINUATION SHEET OF

131 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section III - Facility Information (continued) Facility Compliance Certification Continuation Sheet(s) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping CAS No. - - Monitoring Information Contaminant Name Ambient Air Monitoring Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Facility Emissions Summary CAS No. Contaminant Name NY PM-10 NY PARTICULATES SULFUR DIOXIDE NY OXIDES OF NITROGEN CARBON MONOXIDE LEAD NY VOC NY HAP (lbs/yr) PTE Continuation Sheet(s) Range Code Actual (lbs/yr) 12/21/01 PAGE 3

132 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Emission Unit Description Continuation Sheet(s) Building Continuation Sheet(s) Building Building Name Length (ft) Width (ft) Orientation Emission Point Continuation Sheet(s) EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Cross Section Length (in) Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal Emission Source/Control Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Continuation Sheet(s) Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description 12/21/01 PAGE 4

133 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT Section IV - Emission Unit Information Emission Source/Control (continuation) - Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

134 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Emission Unit Description (continuation) 12/21/01 CONTINUATION SHEET OF

135 New York State Department of Environmental Conservation Air Permit Application DEC ID /21/01 CONTINUATION SHEET OF Section IV - Emission Unit Information Building (continued) Emission Unit Building Building Name Length (ft) Width (ft) Orientation FERC PDF (Unofficial) 9/29/2014 4:29:38 PM

136 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Point (continuation) EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal EMISSION UNIT - EMISSION PT. Ground Elev. (ft) Height (ft) Height Above Structure (ft) Inside Diameter (in) Exit Temp. (EF) Length (in) Cross Section Width (in) Exit Velocity (FPS) Exit Flow (ACFM) NYTM (E) (KM) NYTM (N) (KM) Building Distance to Property Line (ft) Date of Removal 12/21/01 CONTINUATION SHEET OF

137 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT Section IV - Emission Unit Information Emission Source/Control (continuation) - Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description Emission Source Date of Date of Date of Control Type ID Type Construction Operation Removal Code Description Manufacturer s Name/Model No. Design Capacity Design Capacity Units Waste Feed Waste Type Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

138 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information (continued) Process Information Continuation Sheet(s) EMISSION UNIT - PROCESS Description Source Classification Code (SCC) Total Thruput Thruput Quantity Units Quantity/Hr Quantity/Yr Code Description Confidential Operating at Maximum Capacity Activity with Insignificant Emissions Operating Schedule Hrs/Day Days/Yr Building Floor/Location Emission Source/Control Identifier(s) EMISSION UNIT - PROCESS Description Source Classification Code (SCC) Total Thruput Thruput Quantity Units Quantity/Hr Quantity/Yr Code Description Confidential Operating at Maximum Capacity Activity with Insignificant Emissions Operating Schedule Hrs/Day Days/Yr Building Floor/Location Emission Source/Control Identifier(s) 12/21/01 PAGE 5

139 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Process Information (continuation) Continuation Sheet(s) EMISSION UNIT - PROCESS Description Source Classification Code (SCC) Total Thruput Thruput Quantity Units Quantity/Hr Quantity/Yr Code Description Confidential Operating at Maximum Capacity Activity with Insignificant Emissions Operating Schedule Hrs/Day Days/Yr Building Floor/Location Emission Source/Control Identifier(s) EMISSION UNIT - PROCESS Description Source Classification Code (SCC) Total Thruput Thruput Quantity Units Quantity/Hr Quantity/Yr Code Description Confidential Operating at Maximum Capacity Activity with Insignificant Emissions Operating Schedule Hrs/Day Days/Yr Building Floor/Location Emission Source/Control Identifier(s) 12/21/01 CONTINUATION SHEET OF

140 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Emission Unit Emission Point Process Emission Source Section IV - Emission Unit Information (continued) Title Emission Unit Applicable Federal Requirements Continuation Sheet(s) Type Part Sub Part Section Sub Division Parag. Sub Parag. Clause Sub Clause Emission Unit Emission Point Process Emission Source Title Emission Unit State Only Requirements Continuation Sheet(s) Type Part Sub Part Section Sub Division Parag. Sub Parag. Clause Sub Clause Emission Unit Compliance Certification Continuation Sheet(s) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Emission Emission Unit Point Process Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 PAGE 6

141 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Emission Unit Emission Process Emission Point Source Section IV - Emission Unit Information Emission Unit Applicable Federal Requirements (continuation) Title Type Part Sub Part Section Sub Division Parag. Sub Parag. Clause Sub Clause 12/21/01 CONTINUATION SHEET OF

142 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Emission Unit Emission Process Emission Point Source Section IV - Emission Unit Information Emission Unit Applicable Federal Requirements (continuation) Title Type Part Sub Part Section Sub Division Parag. Sub Parag. Clause Sub Clause 12/21/01 CONTINUATION SHEET OF

143 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Unit Compliance Certification (continuation) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No. Contaminant Name Monitoring Information Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

144 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Unit Compliance Certification (continuation) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No. Contaminant Name Monitoring Information Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

145 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Unit Compliance Certification (continuation) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No. Contaminant Name Monitoring Information Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

146 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Unit Compliance Certification (continuation) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No. Contaminant Name Monitoring Information Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

147 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information Emission Unit Compliance Certification (continuation) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No. Contaminant Name Monitoring Information Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Applicable Federal Requirement State Only Requirement Capping Emission Unit Emission Point Process Emission Source CAS No Continuous Emission Monitoring Intermittent Emission Testing Ambient Air Monitoring Monitoring Information Contaminant Name Monitoring of Process or Control Device Parameters as Surrogate Work Practice Involving Specific Operations Record Keeping/Maintenance Procedures Description Work Practice Process Material Type Code Description Reference Test Method Code Parameter Description Manufacturer Name/Model No. Limit Limit Units Upper Lower Code Description Averaging Method Monitoring Frequency Reporting Requirements Code Description Code Description Code Description 12/21/01 CONTINUATION SHEET OF

148 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information (continued) Determination of Non-Applicability (Title V Only) Continuation Sheet(s) Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Emission Unit Emission Point Process Emission Source Applicable Federal Requirement - State Only Requirement Description Rule Citation Title Type Part Sub Part Section Sub Division Paragraph Sub Paragraph Clause Sub Clause Emission Unit Emission Point Process Emission Source Applicable Federal Requirement - State Only Requirement Description Process Emissions Summary EMISSION UNIT - PROCESS CAS No. - - Contaminant Name % Thruput % Capture % Control Continuation Sheet(s) ERP (lbs/hr) ERP How Determined PTE Standard PTE How Actual (lbs/hr) (lbs/yr) (standard units) Units Determined (lbs/hr) (lbs/yr) EMISSION UNIT - PROCESS CAS No. - - Contaminant Name % Thruput % Capture % Control ERP (lbs/hr) ERP How Determined PTE Standard PTE How Actual (lbs/hr) (lbs/yr) (standard units) Units Determined (lbs/hr) (lbs/yr) EMISSION UNIT - PROCESS CAS No. - - Contaminant Name % Thruput % Capture % Control ERP (lbs/hr) ERP How Determined PTE Standard PTE How Actual (lbs/hr) (lbs/yr) (standard units) Units Determined (lbs/hr) (lbs/yr) 12/21/01 PAGE 7

149 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Section IV - Emission Unit Information (continued) EMISSION UNIT - CAS No. - - ERP (lbs/yr) Emission Unit Emissions Summary Contaminant Name PTE Emissions Continuation Sheet(s) Actual (lbs/hr) (lbs/yr) (lbs/hr) (lbs/yr) CAS No. - - ERP (lbs/yr) Contaminant Name PTE Emissions Actual (lbs/hr) (lbs/yr) (lbs/hr) (lbs/yr) CAS No. - - ERP (lbs/yr) Contaminant Name PTE Emissions Actual (lbs/hr) (lbs/yr) (lbs/hr) (lbs/yr) CAS No. - - ERP (lbs/yr) Contaminant Name PTE Emissions Actual (lbs/hr) (lbs/yr) (lbs/hr) (lbs/yr) Compliance Plan Continuation Sheet(s) For any emission units which are not in compliance at the time of permit application, the applicant shall complete the following Consent Order Certified progress reports are to be submitted every 6 months beginning / / Emission Emission Unit Process Source Applicable Federal Requirement Title Type Part Sub Part Section Sub Division Parag. Sub Parag. Clause Sub Clause - Remedial Measure / Intermediate Milestones R/I Date Scheduled 12/21/01 PAGE 8

150 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information (continued) Request for Emission Reduction Credits Emission Reduction Description Continuation Sheet(s) Name Contaminant Emission Reduction Data Baseline Period / / to / / CAS No. Location Address Contaminant Name Date / / Netting Reduction ERC (lbs/yr) Facility to Use Future Reduction APPLICATION ID - - / City / Town / Village State Zip Method Offset EMISSION UNIT - Use of Emission Reduction Credits Proposed Project Description Continuation Sheet(s) Contaminant Emissions Increase Data CAS No. Contaminant Name PEP (lbs/yr) - - Statement of Compliance All facilities under the ownership of this ownership/firm are operating in compliance with all applicable requirements and state regulations including any compliance certification requirements under Section 114(a)(3) of the Clean Air Act Amendments of 1990, or are meeting the schedule of a consent order. Name Location Address Source of Emission Reduction Credit - Facility PERMIT ID - - / City / Town / Village State Zip Emission Unit CAS No. Contaminant Name ERC (lbs/yr) Netting Offset 12/21/01 PAGE 9

151 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Request for Emission Reduction Credits (continuation) Emission Reduction Description CAS No. - - Contaminant Emission Reduction Data Contaminant Name Netting ERC (lbs/yr) Offset /21/01 CONTINUATION SHEET OF

152 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Request for Emission Reduction Credits (continuation) Emission Reduction Description CAS No. - - Contaminant Emission Reduction Data Contaminant Name Netting ERC (lbs/yr) Offset /21/01 CONTINUATION SHEET OF

153 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Request for Emission Reduction Credits (continuation) Emission Reduction Description CAS No. - - Contaminant Emission Reduction Data Contaminant Name Netting ERC (lbs/yr) Offset /21/01 CONTINUATION SHEET OF

154 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Request for Emission Reduction Credits (continuation) Emission Reduction Description CAS No. - - Contaminant Emission Reduction Data Contaminant Name Netting ERC (lbs/yr) Offset /21/01 CONTINUATION SHEET OF

155 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Request for Emission Reduction Credits (continuation) Emission Reduction Description CAS No. - - Contaminant Emission Reduction Data Contaminant Name Netting ERC (lbs/yr) Offset /21/01 CONTINUATION SHEET OF

156 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Use of Emission Reduction Credits (continuation) Proposed Project Description Name Location Address Source of Emission Reduction Credit - Facility PERMIT ID - - / City / Town / Village State Zip Emission Unit CAS No. Contaminant Name ERC (lbs/yr) Netting Offset /21/01 CONTINUATION SHEET OF

157 New York State Department of Environmental Conservation Air Permit Application DEC ID - - EMISSION UNIT - Section IV - Emission Unit Information Use of Emission Reduction Credits (continuation) Proposed Project Description Name Location Address Source of Emission Reduction Credit - Facility PERMIT ID - - / City / Town / Village State Zip Emission Unit CAS No. Contaminant Name ERC (lbs/yr) Netting Offset /21/01 CONTINUATION SHEET OF

158 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Supporting Documentation P.E. Certification (form attached) List of Exempt Activities (form attached) Plot Plan Methods Used to Determine Compliance (form attached) Calculations Air Quality Model ( / / ) Confidentiality Justification Ambient Air Monitoring Plan ( / / ) Stack Test Protocols/Reports ( / / ) Continuous Emissions Monitoring Plans/QA/QC ( / / ) MACT Demonstration ( / / ) Operational Flexibility: Description of Alternative Operating Scenarios and Protocols Title IV: Application/Registration ERC Quantification (form attached) Use of ERC(s) (form attached) Baseline Period Demonstration Analysis of Contemporaneous Emission Increase/Decrease LAER Demonstration ( / / ) BACT Demonstration ( / / ) Other Document(s): ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) ( / / ) 12/21/01 PAGE 10

159 APPENDIX D: NYSDEC P.E. CERTIFICATION FORM Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

160

161 APPENDIX E: NYSDEC LIST OF EXEMPT ACTIVITIES FORM Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

162 New York State Department of Environmental Conservation Air Permit Application DEC ID - - List of Exempt Activities (from NYCRR Part 201) Instructions for Completing Table Applicants for Title V permits are required to provide a list of exempt activities in the application form. This includes all process or production units and other emission generating activities which are considered exempt as defined by 6 NYCRR Part Completion of this table fulfills that requirement. To complete the table, provide the following information for each exempt activity that occurs at the facility defined by this application: a. The approximate number of each listed activity, and, b. For location of the activity enter the building ID(s) used in the main application form. Use the building name if a building ID(s) has not been assigned. If a listed activity does not occur at the facility, leave blank. Combustion Rule Citation (c) Description (1) stationary or portable combustion installations where the furnace has a maximum rated heat input capacity <10mmBtu/hr burning fossil fuels, other than coal, and coal and wood fired stationary combustion units with a maximum heat input <1mmBtu/hr. - this includes unit space heaters, which burn waste oils as defined in 6 NYCRR Part and generated on-site, alone or in conjunction with used oil generated by a do-it-yourself oil changer as defined in 6 NYCRR Subpart (2) stationary or portable combustion installations located outside of any severe ozone non-attainment areas, where the furnace has a maximum rated heat input capacity <20 mmbtu/hr burning fossil fuels other than coal, where the construction of the combustion installation commenced before 6/8/89 (3)(i) (3)(ii) (3)(iii) diesel or natural gas powered stationary or portable internal combustion (IC) engines within any severe ozone non-attainment area having a maximum mechanical power rating <225bhp diesel or natural gas powered stationary or portable IC engines located outside of any severe ozone non-attainment areas having a maximum mechanical power rating <400 bhp gasoline powered IC engines having a maximum mechanical power rating <50bhp (4) stationary or portable IC engines which are temporarily located at a facility for a period <30 days/calendar year, where the total combined maximum mechanical power rating for all affected units is <1000bhp (5) gas turbines with a heat input at peak load <10mmBtu/hr (6) emergency power generating units installed for use when the usual sources of heat, power, water and lighting are temporarily unobtainable, or which are installed to provide power <500 hrs/yr and excluding those units under contract w/ a utility to provide peak shaving generation to the grid Combustion-Related (7) non-contact water cooling towers and water treatment systems for process cooling water and other water containers designed to cool, store or otherwise handle water that has not been in direct contact with gaseous or liquid process streams No. of Activities (approx.) Building Location 10/31/96 CONTINUATION SHEET 1 OF 4

163 New York State Department of Environmental Conservation Air Permit Application DEC ID - - List of Exempt Activities (from NYCRR Part 201) Agricultural Rule Citation (c) Description No. of Activities (approx.) Building Location (8) feed and grain milling, cleaning, conveying, drying and storage operations including grain storage silos, where such silos exhaust to an appropriate emission control device, excluding grain terminal elevators with permanent storage capacities over 2.5 million US bushels, and grain storage elevators with capacities above 1 million bushels (9) equipment used exclusively to slaughter animals, but not including other equipment at slaughterhouses, such as rendering cookers, boilers, heating plants, incinerators and electrical power generating equipment Commercial-Food Service Industries (10) flour silos at bakeries, provided all such silos are exhausted through an appropriate emission control device (11) emissions from flavorings, added to a food product where such flavors are manually added to the product Commercial-Graphic Arts (12) screen printing inks/coatings or adhesives which are applied by a hand-held squeegee (i.e. one that is not propelled thru the use of mechanical conveyance and is not an integral part of the screen printing process) (13) graphic arts processes at facilities located outside the NYC metropolitan area whose facility-wide total emissions or VOC s from inks, coatings, adhesives, fountain solutions and cleaning solutions does not exceed 20 lbs/day (14) graphic label and/or box labeling operations where the inks are applied by stamping or rolling (15) graphic arts processes which are specifically exempted from regulation under Part 234 with regard to emissions of VOC s which are not given an A rating Commercial-Other (16) gasoline dispensing sites with an annual thruput <120,000 gal located outside any severe non-attainment areas (17) surface coating related operations which use less than 25 gal/mo of coating materials (paints) and cleaning solvents, combined, subject to the following: - the facility is located outside of severe ozone non-attainment area - -all abrasive cleaning and surface coating operations are performed in an enclosed building where such operations are exhausted into appropriate emission control devices (18) abrasive cleaning operations which exhaust to an appropriate emission control device (19) ultraviolet curing operations Municipal/Public Health Related (20) ventilating systems for landfill gases, where the systems are vented directly to the atmosphere, and the ventilating system has been required by, and is operating under, the conditions of a valid Part 360 permit, or Order on Consent 10/31/96 CONTINUATION SHEET 2 OF 4

164 New York State Department of Environmental Conservation Air Permit Application DEC ID - - List of Exempt Activities (from NYCRR Part 201) Storage Vessels Rule Citation (c) Description No. of Activities (approx.) Building Location (21) distillate and residual fuel oil storage tanks with storage capacities <300,000 bbls (22) pressurized fixed roof tanks which are capable of maintaining a working pressure at all times to prevent emissions of VOC s to the outdoor atmosphere (23) external floating roof tanks which are of welded construction and are equipped with a metallic-type shoe primary seal and a secondary seal from the top of the shoe seal to the tank wall (24)(i) (24)(ii) (24)(iii) (24)(iv) external floating roof tanks which are used for the storage of a petroleum or volatile organic liquid with a true vapor pressure <4.0 psi (27.6 kpa), are of welded construction and are equipped with a metallic-type shoe seal external floating roof tanks which are used for the storage of a petroleum or volatile organic liquid with a true vapor pressure <4.0 psi (27.6 kpa), are of welded construction and are equipped with a liquid-mounted foam seal external floating roof tanks which are used for the storage of a petroleum or volatile organic liquid with a true vapor pressure <4.0 psi (27.6 kpa), are of welded construction and are equipped with a liquid-mounted liquid-filled type seal external floating roof tanks which are used for the storage of a petroleum or volatile organic liquid with a true vapor pressure <4.0 psi (27.6 kpa), are of welded construction and are equipped with a control equipment or device equivalent to those previously listed in items (24) (i) thru (iii) (25) storage tanks, with capacities <10,000 gal, except those subject to either Part 229 or Part 233 (26) horizontal petroleum storage tanks (27) storage silos storing solid materials, provided all such soils are exhausted thru an appropriate emission control device Industrial (28) processing equipment at existing sand and gravel and stone crushing plants which were installed or constructed before 8/31/83, where water is used other than for dust suppression, such as wet conveying, separating and washing (29)(i) (29)(ii) all processing equipment at sand and gravel mines or quarries that permanent or fixed installations with a maximum rated processing capacity <25 tph of minerals all processing equipment at sand and gravel mines or quarries that mobile (portable) installations with a maximum rated processing capacity <150 tph of minerals (30) mobile (portable) stone crushers with maximum rated capacities <150 tph of minerals which are located at nonmetallic mineral processing operations (31) surface coating operations which are specifically exempted from regulation under Part 228, with regard to emissions of VOC s which are not given an A rating (32) pharmaceutical tablet branding operations (33) thermal packaging operations, including but not limited to, therimage labelling, blister packing, shrink wrapping, shrink banding, and carton gluing 10/31/96 CONTINUATION SHEET 3 OF 4

165 New York State Department of Environmental Conservation Air Permit Application DEC ID - - Rule Citation (c) (34) powder coating operations List of Exempt Activities (from NYCRR Part 201) Industrial (continued) Description (35) all tumblers used for the cleaning and/or deburring of metal products without abrasive blasting (36) presses used exclusively for molding or extruding plastics except where halogenated carbon compounds or hydrocarbon solvents are used as foaming agents (37) concrete batch plants where the cement weigh hopper and all bulk storage silos are exhausted thru fabric filters, and the batch drop point is controlled by a shroud or other emission control device (38) cement storage operations where materials are transported by screw or bucket conveyors (39)(i) (39)(ii) (39)(iii) non-vapor phase cleaning equipment with an open surface area <11 sq ft and an internal volume <93 gal or, having an organic solvent loss <3 gal/day non-vapor phase cleaning equipment using only organic solvents with an initial boiling point >300EF at atmospheric pressure non-vapor phase cleaning equipment using materials with a VOC content <2% by volume Miscellaneous (40) ventilating and exhaust systems for laboratory operations (41) exhaust or ventilating systems for the melting of gold, silver, platinum, and other precious metals (42) exhaust systems for paint mixing, transfer, filling or sampling and/or solvent storage rooms or cabinets, provided the paints stored within these locations are stored in closed containers when not is use (43) exhaust systems for solvent transfer, filling or sampling and/or solvent storage rooms provided the solvent stored within these locations are stored in closed containers when not is use (44) research and development activities, including both stand-alone and activities within a major stationary source, until such time as the Administrator completes a rulemaking to determine how the permitting program should be constructed for these activities (45) the application of odor counteractants and/or neutralizers No. of Activities (approx.) Building Location 10/31/96 CONTINUATION SHEET 4 OF 4

166 APPENDIX F: NYSDEC METHODS USED TO DETERMINE COMPLIANCE FORM Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

167 New York State Department of Environmental Conservation Air Permit Application DEC ID - - METHODS USED TO DETERMINE COMPLIANCE Emission Unit ID Applicable Requirement Method Used to Determine Compliance and Corresponding Date 12/21/01

168 APPENDIX G: EMISSION REDUCTION CREDIT QUANTIFICATION AND USE FORMS Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

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170 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Nonattainment Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x VOC PM-2.5 PM-10 SO 2 A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits as emission offsets or for netting purposes. Page 2 of 4 3/16/2012 Version 3.6

171 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable nonattainment contaminant (attach data summaries and calculations): NO x VOC PM-2.5 PM-10 SO 2 B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / VOC / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / SO 2 / / / / / / *- Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 Lines B.4, B.5 and B.6 NOTES. 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 3 of 4 3/16/2012 Version 3.6

172 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x VOC PM-2.5 PM-10 SO 2 Page 4 of 4 3/16/2012 Version 3.6

173

174 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Regulated NSR Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits for netting purposes. Page 2 of 6 3/16/2012 Version 2.5

175 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable Regulated NSR Contaminant (attach data summaries and calculations): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / PM / / / / / / CO / / / / / / SO 2 / / / / / / Other: / / / / / / / / / / / / * - Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 3 of 6 3/16/2012 Version 2.5

176 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Lines B.4, B.5 and B.6 NOTES: 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 4 of 6 3/16/2012 Version 2.5

177 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 5 of 6 3/16/2012 Version 2.5

178 APPENDIX Carbon monoxide Nitrogen oxides Sulfur dioxide Particulate matter Particulate matter: PM-10 emissions (including condensibles) Particulate matter: PM-2.5 emissions (including condensibles) Lead (elemental) Fluorides Sulfuric acid mist Hydrogen sulfide (H 2 S) Total reduced sulfur (including H 2 S) Reduced sulfur compounds (including H 2 S) Municipal waste combustor organics (measured as total tetra through octa-chlorinated dibenzo-p-dioxin and dibenzofurans) Municipal waste combustor metals (measured as particulate matter) Municipal waste combustor acid gases (measured as sulfur dioxide and hydrogen chloride) Municipal solid waste landfills emissions (measured as nonmethane organic compounds) Greenhouse gases Any other regulated NSR contaminant Page 6 of 6 3/16/2012 Version 2.5

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180 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Nonattainment Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x VOC PM-2.5 PM-10 SO 2 A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits as emission offsets or for netting purposes. Page 2 of 4 3/16/2012 Version 3.6

181 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable nonattainment contaminant (attach data summaries and calculations): NO x VOC PM-2.5 PM-10 SO 2 B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / VOC / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / SO 2 / / / / / / *- Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 Lines B.4, B.5 and B.6 NOTES. 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 3 of 4 3/16/2012 Version 3.6

182 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x VOC PM-2.5 PM-10 SO 2 Page 4 of 4 3/16/2012 Version 3.6

183

184 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Regulated NSR Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits for netting purposes. Page 2 of 6 3/16/2012 Version 2.5

185 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable Regulated NSR Contaminant (attach data summaries and calculations): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / PM / / / / / / CO / / / / / / SO 2 / / / / / / Other: / / / / / / / / / / / / * - Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 3 of 6 3/16/2012 Version 2.5

186 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Lines B.4, B.5 and B.6 NOTES: 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 4 of 6 3/16/2012 Version 2.5

187 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 5 of 6 3/16/2012 Version 2.5

188 APPENDIX Carbon monoxide Nitrogen oxides Sulfur dioxide Particulate matter Particulate matter: PM-10 emissions (including condensibles) Particulate matter: PM-2.5 emissions (including condensibles) Lead (elemental) Fluorides Sulfuric acid mist Hydrogen sulfide (H 2 S) Total reduced sulfur (including H 2 S) Reduced sulfur compounds (including H 2 S) Municipal waste combustor organics (measured as total tetra through octa-chlorinated dibenzo-p-dioxin and dibenzofurans) Municipal waste combustor metals (measured as particulate matter) Municipal waste combustor acid gases (measured as sulfur dioxide and hydrogen chloride) Municipal solid waste landfills emissions (measured as nonmethane organic compounds) Greenhouse gases Any other regulated NSR contaminant Page 6 of 6 3/16/2012 Version 2.5

189

190 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Nonattainment Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x VOC PM-2.5 PM-10 SO 2 A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits as emission offsets or for netting purposes. Page 2 of 4 3/16/2012 Version 3.6

191 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable nonattainment contaminant (attach data summaries and calculations): NO x VOC PM-2.5 PM-10 SO 2 B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / VOC / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / SO 2 / / / / / / *- Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 Lines B.4, B.5 and B.6 NOTES. 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 3 of 4 3/16/2012 Version 3.6

192 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x VOC PM-2.5 PM-10 SO 2 Page 4 of 4 3/16/2012 Version 3.6

193

194 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Regulated NSR Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits for netting purposes. Page 2 of 6 3/16/2012 Version 2.5

195 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable Regulated NSR Contaminant (attach data summaries and calculations): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / PM / / / / / / CO / / / / / / SO 2 / / / / / / Other: / / / / / / / / / / / / * - Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 3 of 6 3/16/2012 Version 2.5

196 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Lines B.4, B.5 and B.6 NOTES: 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 4 of 6 3/16/2012 Version 2.5

197 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 5 of 6 3/16/2012 Version 2.5

198 APPENDIX Carbon monoxide Nitrogen oxides Sulfur dioxide Particulate matter Particulate matter: PM-10 emissions (including condensibles) Particulate matter: PM-2.5 emissions (including condensibles) Lead (elemental) Fluorides Sulfuric acid mist Hydrogen sulfide (H 2 S) Total reduced sulfur (including H 2 S) Reduced sulfur compounds (including H 2 S) Municipal waste combustor organics (measured as total tetra through octa-chlorinated dibenzo-p-dioxin and dibenzofurans) Municipal waste combustor metals (measured as particulate matter) Municipal waste combustor acid gases (measured as sulfur dioxide and hydrogen chloride) Municipal solid waste landfills emissions (measured as nonmethane organic compounds) Greenhouse gases Any other regulated NSR contaminant Page 6 of 6 3/16/2012 Version 2.5

199

200 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Nonattainment Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x VOC PM-2.5 PM-10 SO 2 A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits as emission offsets or for netting purposes. Page 2 of 4 3/16/2012 Version 3.6

201 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable nonattainment contaminant (attach data summaries and calculations): NO x VOC PM-2.5 PM-10 SO 2 B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / VOC / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / SO 2 / / / / / / *- Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 Lines B.4, B.5 and B.6 NOTES. 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 3 of 4 3/16/2012 Version 3.6

202 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x VOC PM-2.5 PM-10 SO 2 Page 4 of 4 3/16/2012 Version 3.6

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204 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Regulated NSR Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits for netting purposes. Page 2 of 6 3/16/2012 Version 2.5

205 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable Regulated NSR Contaminant (attach data summaries and calculations): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / PM / / / / / / CO / / / / / / SO 2 / / / / / / Other: / / / / / / / / / / / / * - Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 3 of 6 3/16/2012 Version 2.5

206 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Lines B.4, B.5 and B.6 NOTES: 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 4 of 6 3/16/2012 Version 2.5

207 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 5 of 6 3/16/2012 Version 2.5

208 APPENDIX Carbon monoxide Nitrogen oxides Sulfur dioxide Particulate matter Particulate matter: PM-10 emissions (including condensibles) Particulate matter: PM-2.5 emissions (including condensibles) Lead (elemental) Fluorides Sulfuric acid mist Hydrogen sulfide (H 2 S) Total reduced sulfur (including H 2 S) Reduced sulfur compounds (including H 2 S) Municipal waste combustor organics (measured as total tetra through octa-chlorinated dibenzo-p-dioxin and dibenzofurans) Municipal waste combustor metals (measured as particulate matter) Municipal waste combustor acid gases (measured as sulfur dioxide and hydrogen chloride) Municipal solid waste landfills emissions (measured as nonmethane organic compounds) Greenhouse gases Any other regulated NSR contaminant Page 6 of 6 3/16/2012 Version 2.5

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210 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Nonattainment Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x VOC PM-2.5 PM-10 SO 2 A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits as emission offsets or for netting purposes. Page 2 of 4 3/16/2012 Version 3.6

211 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable nonattainment contaminant (attach data summaries and calculations): NO x VOC PM-2.5 PM-10 SO 2 B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / VOC / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / SO 2 / / / / / / *- Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x VOC PM-2.5 PM-10 SO 2 Lines B.4, B.5 and B.6 NOTES. 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 3 of 4 3/16/2012 Version 3.6

212 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x VOC PM-2.5 PM-10 SO 2 B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x VOC PM-2.5 PM-10 SO 2 Page 4 of 4 3/16/2012 Version 3.6

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214 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of the Baseline Period for the reduction(s) A.1 Emission Reduction Regulated NSR Contaminant (circle all that apply to a specific emission reduction action at an emission source): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : A.2 Emission Reduction Date: / / NOTE: The emission reduction date is the date that the emission reduction(s) physically occurred (past reduction), or the date the reduction(s) is/are scheduled to occur (future reduction). A.3 Describe action(s) taken (or to be taken) to reduce emissions for which ERC(s) is/are requested: A.4 Baseline Period ( (b)(7)) for the emission reduction(s): / / to / / Line A.4 NOTES: 1. The same Baseline Period must be used for all applicable contaminants identified in A.1 above. 2. For an emission reduction which has physically occurred (past reduction), the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the emission reduction date (Line A.2 above). 3. For a future emission reduction, the Baseline Period consists of any 24 consecutive months within the five (5) years immediately preceding the date of receipt by the Department of the permit application for the project which proposes to use the emission reduction credits for netting purposes. Page 2 of 6 3/16/2012 Version 2.5

215 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Baseline Actual Emissions for the reduction(s) B.1 Enter the Baseline Actual Emissions ( (b)(4)) in tons per year (tpy) for each applicable Regulated NSR Contaminant (attach data summaries and calculations): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.2 State Register or Federal Register publication notice date proposing any RACT, MACT or other control requirement (OCR) that may be applicable to the emission source for which ERCs are requested: Contaminant RACT Date MACT Date OCR Date * NO x / / / / / / PM-2.5 / / / / / / PM-10 / / / / / / PM / / / / / / CO / / / / / / SO 2 / / / / / / Other: / / / / / / / / / / / / * - Identify OCR that applies: B.3 Emission Reduction Date (from Line A.2 on page 2) / / B.4 What are the Baseline Actual Emissions reflecting RACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 3 of 6 3/16/2012 Version 2.5

216 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: B.5 What are the Baseline Actual Emissions reflecting MACT, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.6 What are the Baseline Actual Emissions reflecting OCR, if applicable (tpy)? (see notes) NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Lines B.4, B.5 and B.6 NOTES: 1. Attach data summaries and calculations. 2. For a past emission reduction that physically occurred after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. 3. For a future emission reduction, if the date that the emission reduction credits are approved is after a State or Federal Register publication date proposing an applicable RACT, MACT or OCR, then the Baseline Actual Emissions must be adjusted to reflect the applicable RACT, MACT or OCR. Page 4 of 6 3/16/2012 Version 2.5

217 Emission Reduction Credit Quantification Form (con t) DEC ID#: Emission Source ID#: Determination of Emission Reduction Credit(s) B.7 Enter the lesser of the Baseline Actual Emissions from Lines B.1, B.4, B.5 or B.6 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.8 Enter the future Potential-To-Emit (PTE) as defined in 6 NYCRR Part 200 (tpy): NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : B.9 Subtract Line B.8 from Line B.7. These are the emission reduction credits (tpy). If Line B.8 is greater than Line B.7, enter zero. NO x PM-2.5 PM-10 PM CO SO 2 Other Applicable Regulated NSR Contaminant - (See Appendix): : ; : Page 5 of 6 3/16/2012 Version 2.5

218 APPENDIX Carbon monoxide Nitrogen oxides Sulfur dioxide Particulate matter Particulate matter: PM-10 emissions (including condensibles) Particulate matter: PM-2.5 emissions (including condensibles) Lead (elemental) Fluorides Sulfuric acid mist Hydrogen sulfide (H 2 S) Total reduced sulfur (including H 2 S) Reduced sulfur compounds (including H 2 S) Municipal waste combustor organics (measured as total tetra through octa-chlorinated dibenzo-p-dioxin and dibenzofurans) Municipal waste combustor metals (measured as particulate matter) Municipal waste combustor acid gases (measured as sulfur dioxide and hydrogen chloride) Municipal solid waste landfills emissions (measured as nonmethane organic compounds) Greenhouse gases Any other regulated NSR contaminant Page 6 of 6 3/16/2012 Version 2.5

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220 APPENDIX H: NAAQS AND DAR-1 MODELING ANALYSES Algonquin Stony Point Compressor Station Title V Permit Modification Application 2014 Trinity Consultants

221 MODELING REPORT Algonquin Gas Transmission, LLC > Stony Point Station Air Dispersion Modeling Prepared By: Trinity Consultants TRINITY CONSULTANTS 5 Great Valley Parkway Suite 322 Malvern, PA (610) June 2014 Environmental solutions delivered uncommonly well

222 TABLE OF CONTENTS 1. INTRODUCTION Background Site Description MODELING REQUIREMENTS NAAQS Analysis Background Concentrations from Ambient Monitoring Toxic Contaminants MODELING METHODOLOGY Model Selection Meteorological Data Surface Data Upper Air Sounding Data AERMET Data Processing Land Use Analysis Terrain Receptor Grid Building Wake Effect (Downwash) GEP Stack Height Source Parameters and Emissions NO 2 Modeling Options RESULTS PM 10 NAAQS Analysis PM 2.5 NAAQS Analysis NO 2 NAAQS Analysis CO NAAQS Analysis SO 2 NAAQS Analysis HCHO AGC and SGC Analysis ELECTRONIC FILES 5-1 ATTACHMENT A DAR-1 AERSCREEN ANALYSIS A-1 Background... A 1 Modeled Emission Sources... A 1 Modeling methodology... A 3 Analysis Results... A 5 Modeling Summary... A 11 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants i

223 LIST OF FIGURES Figure 1 1. Area Map 1 2 Figure 1 2. Facility Layout 1 3 Figure 3 1. Candidate Surface Met Station Locations 3 2 Figure 3 2. Aerial Image of 3 km Radius around Stony Point Station 3 6 Figure 3 3. NLCD92 Image of 3 km Radius around Stony Point Station 3 7 Figure 3 4. Receptor Grid 3 9 Figure 3 5. Emission Point Locations 3 13 Figure hour PM 2.5 Impacts Scenario Figure 4 2. Annual PM 2.5 Impacts Scenario Figure hr NO 2 Impacts Scenario Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants ii

224 LIST OF TABLES Table 2 1. Primary National Ambient Air Quality Standards (NAAQS) Table 2 2. Selected Monitoring Stations for Background Concentrations Table 2 3. Three Year Average of Scranton NO2 Background Concentration Table 2 4. Short Term and Annual Guideline Concentrations for HCHO Table 3 1. Comparison of Site Elevations Table 3 2. Comparison of Airport Meteorological Station Data Quality Table 3 3. Building Dimensions Table 3 4. Emission Point Descriptions and Locations Table 3 5. Modeled Stack Parameters for Project Equipment Table 3 6. Modeled Emission Rates for Project Equipment Table 3 7. Modeled Stack Parameters for Existing Equipment Table 3 8. Modeled Emission Rates for Existing Equipment Table hour PM 10 Modeled Results Table hour and Annual PM 2.5 Modeled Results Table hour and Annual NO 2 Modeled Results Table hour and 8 hour CO Modeled Results Table hour, 3 hour, 24 hour, and Annual SO 2 Modeled Results Table 4 6. Short Term and Annual HCHO Modeled Results Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants iii

225 1. INTRODUCTION Algonquin Gas Transmission, LLC ("Algonquin") is proposing to increase the pipeline size and compressor station horsepower along Algonquin s existing mainline from Ramapo, New York to multiple mainline delivery points in Connecticut and Massachusetts and greenfield facilities for lateral to West Roxbury, Massachusetts. Collectively, this project is referred to as the Algonquin Incremental Market (AIM) Project. The AIM Project will require the addition of horsepower at five existing compressor stations, including the Stony Point compressor station in Stony Point, New York. Algonquin also is proposing to upgrade existing equipment through several modifications and environmental improvements under a separate Algonquin Gas Transmission (AGT) project. The AIM and AGT projects are referred to collectively throughout this report as the Project BACKGROUND At the state level, the Project triggers a significant Title V permit modification through the New York State Department of Environmental Conservation (NYSDEC). If the agency considers that any project triggering minor NSR permitting could threaten attainment with the National Ambient Air Quality Standards (NAAQSs) or human health from toxic air pollutant (TAP) concentrations, NYSDEC can require air dispersion modeling for the Project. NYSDEC has requested that Algonquin perform a sitewide modeling analysis for criteria pollutants in accordance with their impact analysis modeling guidance, Policy DAR 10. In addition, NYSDEC has asked for a modeling analysis that addresses TAPs from the proposed project equipment per Policy DAR 1. To meet these requests, Algonquin has performed a combination of AERMOD modeling for criteria pollutants and formaldehyde and AERSCREEN modeling for TAPs. This report outlines the modeling reflecting updated project designs which was performed to support the NYSDEC air permit application and to respond to NYSDEC s requests SITE DESCRIPTION The Algonquin facility is a permitted Title V source (Permit ID /00027) and is located off Cedar Flats Road on Lindberg Road, west of Stony Point. The aerial map presented in Figure 1 1 shows the approximate center of the facility (582,170 meters [m] Easting and 4,566,130 m Northing in Universal Transverse Mercator [UTM] Zone 18, Northern Hemisphere, North American Datum 1983 [NAD83]). Inset is a smaller map, indicating the facility s location in the southeastern region of New York. Figure 1 2 shows the layout of the facility. The facility is composed of eight buildings. More detail about the building heights and names can be found in Table 3 3. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 1-1

226 Figure 1 1. Area Map Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 1-2

227 Figure 1 2. Facility Layout Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 1-3

228 2. MODELING REQUIREMENTS This section outlines the modeling procedures used in this analysis. The air dispersion modeling analysis was conducted in a manner consistent with the following: > Environmental Protection Agency s (EPA) Appendix W of 40 CFR 51, the Guideline on Air Quality Models (Guideline;) 1 > NYSDEC s Policy DAR 10: Guidelines on Dispersion Modeling Procedures for Air Quality Impact Analysis ; 2 > U.S. EPA s AERMOD Implementation Guide and > U.S. EPA, Office of Air Quality Planning and Standards, Memorandum from Mr. Tyler Fox to Regional Air Division Directors. Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1 hour NO 2 National Ambient Air Quality Standard (March 1, 2011) NAAQS ANALYSIS The primary NAAQS are the maximum concentration ceilings, measured in terms of total concentration of a pollutant in the atmosphere, which define the levels of air quality which the U.S. EPA judges are necessary, with an adequate margin of safety, to protect the public health. 3 Secondary NAAQS define the levels that protect the public welfare from any known or anticipated adverse effects of a pollutant. The objective of the NAAQS analysis is to demonstrate through air quality modeling that emissions from a proposed project do not contribute to or cause an exceedance of the NAAQS at any ambient location. Table 2 1 lists the primary NAAQS for the following pollutants: Particulate matter with an aerodynamic diameter of less than 10 microns (PM 10 ); Particulate matter with an aerodynamic diameter of less than 2.5 microns (PM 2.5 ); Sulfur dioxide (SO 2 ); Nitrogen dioxide (NO 2 ); and, Carbon monoxide (CO) Federal Register 68218, November 9, CFR 50.2(b) Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-1

229 Table 2 1. Primary National Ambient Air Quality Standards (NAAQS) Pollutant Averaging Period Modeled Form NAAQS (µg/m 3 ) PM hour H8H, averaged over 5 years 35.0 NO2 Annual H1H, averaged over 5 years 12.0 H8H (max daily 1 hr), averaged over 5 1 hour years Annual* H1H CO 1 hour H2H hour H2H PM10 24 hour H6H over 5 years H4H (max daily 1 hr), averaged over 5 SO2 1 hour years hour H2H hour H2H Annual H1H 80.0 *A slightly different Ambient Air Quality Standard (AAQS) exists in New York for annual average NO2. A NAAQS analysis also requires consideration of external, non Algonquin sources of emissions. To account for these emissions, Algonquin is adding representative background values (discussed in Section 2.1.1) to the model output concentrations that conservatively account for external emissions sources near the Stony Point Compressor Station Background Concentrations from Ambient Monitoring Background concentrations for inclusion in the NAAQS demonstration were obtained from NYSDEC and Pennsylvania Department of Environmental Protection (PADEP) operated monitoring stations. Tabled below are the selected monitoring stations and the most recent three year ( ) design values for each pollutant and averaging period. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-2

230 Table 2 2. Selected Monitoring Stations for Background Concentrations Pollutant Averaging Period Monitoring Station AQS Site ID County State Approx. Distance from Facility (km) Background Concentration (ug/m 3 ) NO2 1 hour Scranton Lackawanna PA NO2 Annual Scranton Lackawanna PA PM hour Newburgh Orange NY PM2.5 Annual Newburgh Orange NY CO 1 hour Westport Sherwood Island Fairfield CT 59 1,150.0 CO 8 hour Westport Sherwood Island Fairfield CT PM10 24 hr New Haven Criscuolo New Haven CT SO2 1 hour Nysdec Field Hqtrs Gypsy Trail Road Putnam NY Primary NAAQS (ug/m 3 ) SO2 3 hour Nysdec Field Hqtrs Gypsy Trail Road Putnam NY ,300.0 SO2 24 hour Nysdec Field Hqtrs Gypsy Trail Road Putnam NY SO2 Annual Nysdec Field Hqtrs Gypsy Trail Road Putnam NY , ,000.0 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-3

231 NO 2 Background Concentrations There are eight potential candidate NO 2 monitoring stations including the following: Pfizer Lab Site (Bronx, NY) (ID ) 44 km New Haven Criscuolo (New Haven County CT) (ID ) 93 km Sherwood Island (Fairfield County CT) (ID ) 59 km Queens College (Queens, NY) (ID ) 60 km Chester Township (Morris County NJ) (ID ) 76 km Cornwall (Litchfield County CT) (ID ) 88 km Knolton Township (Warren County NJ) (ID ) 94 km Scranton (Lackawanna County PA) (ID ) 136 km The two sites in New York City (ID and ) are not considered most representative because the concentrations monitored are indicative of a highly urban area, not rural as in the case of the Stony Point Station. Similarly, the New Haven Criscuolo station is located in an urban area and is, therefore, not considered most representative. Two Connecticut sites (ID and ) and the Knolton Township monitor are excluded from consideration because the monitoring data do not meet EPA s completeness criteria. With regard to the remaining sites, the Scranton monitor is more distant than the other candidate, Chester Township. However, the site has reasonably similar land use characteristics and is generally upwind of the project area. Furthermore, traffic counts near the Scranton monitor are more indicative (and conservative) of those near the Stony Point Station. As such, this site was selected as the most representative monitor for the Stony Point Station. It is worth noting here that Algonquin, in keeping with EPA approved procedures, opted to refine the NO 2 background concentration value for inclusion in the 1 hour NAAQS modeling analysis. Specifically, Algonquin has used the multi year average of the 98 th percentile of the available Scranton concentrations by season and hour of day. 4 The refined NO 2 background data can be seen in Table U.S. EPA Memorandum from Tyler Fox, Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard, March 1, Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-4

232 Table 2 3. Three Year Average of Scranton NO2 Background Concentration 3 Year Average Hour Winter Spring Summer Fall (ppb) (ppb) (ppb) (ppb) CO Background Concentration With respect to CO, there are five potential candidate monitoring stations, excluding those in the densely populated New York City, NY area. The sites are as follows: > Westport Sherwood Island (Fairfield County CT) (ID ) 59 km > Bridgeport Roosevelt (Fairfield County CT) (ID ) 72 km > Cornwall (Litchfield County CT) (ID ) 88 km > Freemansburg (Northampton County PA) (ID ) 131 km > Scranton (Lackawanna County PA) (ID ) 136 km > Loudounville (Albany County NY) (ID ) 161 km Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-5

233 Each of the sites has complete data and all are located near relatively high density population bases. Given its proximity to the Stony Point Compressor Station, compared to the other sites, as well as Interstate 95, the Westport Sherwood Island monitor was selected for use in the analysis. The selected data should provide a representative, yet conservative, estimate of ambient background concentrations PM 2.5 Background Concentrations There were eight potential candidate sites reviewed for representativeness of PM 2.5 background concentrations. The sites reviewed included the following: Newburgh (Orange County NY) (ID ) 28 km Danbury (Fairfield County CT) (ID ) 50 km Norwalk (Fairfield County CT) (ID ) 52 km Westport Sherwood Island (Fairfield County CT) (ID ) 59 km Division Street (New York, NY) (ID ) 59 km Queens College (Queens, NY) (ID ) 60 km Bridgeport Roosevelt (Fairfield County CT) (ID ) 72 km Cornwall (Litchfield County CT) (ID ) 88 km Of these sites, the Newburgh, New York ambient PM 2.5 monitoring station (ID ) was selected for Stony Point as the most representative station of five potential candidates. The Newburgh monitoring station is located approximately 30 km from the station and its location has characteristics similar to that of the project site. In addition to being the closest station to Stony Point, the monitor is similarly located on the west side of the Hudson River valley. The monitor is also situated in a more densely populated area, which could yield slightly more conservative background concentrations PM 10 Background Concentrations Given that most areas attain the PM 10 standards, the focus on ambient monitoring for particulates has shifted to PM 2.5. As such, excluding monitors located in the New York City area, there are limited PM 10 monitors in general. Note that other monitors record PM 10 data in Connecticut but these stations have been identified as providing estimates only and do not meet EPA completeness criteria. The four monitors considered in this analysis were: New Haven Criscuolo (New Haven County CT) (ID ) 93 km Wilkes Barre (Luzerne County PA) (ID ) 153 km Allentown (Lehigh County PA) (ID ) 140 km Nazareth (Northampton County PA) (ID ) 125 km Due to its proximity and the expectation that data would provide for a conservatively high ambient background concentration (i.e., it is situated in a more urban setting then the site), the New Haven monitor was selected for PM SO 2 Background Concentrations Finally, with respect to SO 2, there were eight candidate sites evaluated, excluding urban monitors previously noted as not being the most representative monitoring sites (e.g., New York City sites). The stations evaluated were as follows: Mt. Ninham (Putnam County NY) (ID ) 34 km Westport Sherwood Island (Fairfield County CT) (ID ) 59 km Millbrook (Dutchess County NY) (ID ) 64 km Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-6

234 Bridgeport (Fairfield County CT (ID ) 72 km Chester Township (Morris County NJ) (ID ) 76 km Cornwall (Litchfield County CT) (ID ) 88 km New Haven Criscuolo (New Haven County CT) (ID ) 93 km Knolton Township (Warren County NJ) (ID ) 94 km Of these eight stations, the Millbrook, Westport Sherwood Island and Knolton Township monitors do not have the requisite three years of data collection. As noted previously, Bridgeport and New Haven are two of the most populous cities in Connecticut. As such, these are not the most representative monitors of the candidate sites. Each of the three remaining sites have complete data. However, Mt. Ninham is significantly closer than the remaining sites and was thus chosen for use in the analysis TOXIC CONTAMINANTS In addition to the federal NAAQS, New York State has promulgated state specific health effect based annual and short term (1 hour) guideline concentrations (AGCs and SGCs) for toxic air contaminants. These AGCs and SGCs provide maximum air quality levels that are not to be exceeded at any location in the state. Per NYSDEC s Policy DAR 1: Guidelines for the Control of Toxic Ambient Air Contaminants, dispersion modeling is required in NYS to estimate impacts of requires an air quality impact estimate for non criteria air pollutants (i.e., those without a NAAQS) regulated under 6 NYCRR Part 212. In keeping with this policy and NYSDEC s request that Algonquin perform toxics modeling for the Project sources, Algonquin has performed an AERSCREEN modeling analysis (i.e., a screening analysis) to compare project related model output concentrations against the AGCs and SGCs. This analysis is included as Attachment A to this modeling report. Due to the conservative nature of screening models, particularly when trying to aggregate impacts from different emission points, Algonquin also performed refined modeling in AERMOD for formaldehyde (HCHO). The same methodology outlined in this report that was employed for analyzing criteria pollutants was also applied to the assessment of formaldehyde from the Project. The maximum model output ground level concentrations of HCHO were compared to the applicable AGC and SGC, shown in Table 2 4. Results of the HCHO analysis are provided in Table 4 6. Table 2 4. Short Term and Annual Guideline Concentrations for HCHO Design Value Pollutant Averaging Period Statistical Form (µg/m 3 ) 1 hour H1H 30 HCHO Annual H1H 0.06 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 2-7

235 3. MODELING METHODOLOGY 3.1. MODEL SELECTION AERMOD (version 14134) is the dispersion model that was used in this analysis. AERMOD is a refined, steadystate, multiple source, Gaussian dispersion model. It was selected because it is EPA s preferred model for nearfield analysis of industrial sources. The analysis was performed using regulatory defaults METEOROLOGICAL DATA AERMOD modeling analyses require the use of meteorological data that has been collected at either an onsite location or a location with similar, representative land use and topographic features to the proposed site. Because a meteorological tower has not been set up or operated onsite at the Stony Point station, representative nearby surface and upper air sounding data were used instead. The meteorological data used in this analysis were processed in the AERMOD pre processor AERMET (version 14134) and were provided to Trinity by NYSDEC. The dataset consists of years 2009 through 2013 derived from surface data observed at the Dutchess County Airport meteorological station (WBAN #14757) and upper air data collected from Albany County Airport upper air sounding station (WBAN #54775). The following subsections describe how the NYSDEC approved meteorological data reasonably represents the meteorological conditions at the Stony Point Station and are appropriate to use in air dispersion modeling Surface Data Trinity considered three (3) National Weather Service (NWS) stations as candidates for the surface meteorological data in the dispersion modeling analyses: Dutchess County Airport (POU) approximately 44 km northeast of the facility Westchester County Airport (HPN) approximately 33 km southeast of the facility Orange County Airport (MGJ) approximately 36 km northwest of the facility Figure 3 1 shows the relative locations of these meteorological sites to the Stony Point facility. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-1

236 Figure 3 1. Candidate Surface Met Station Locations Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-2

237 The Guideline lists the following criteria for determining meteorological data representativeness: The proximity of the meteorological station to the area under consideration; The complexity of the terrain; The exposure of the meteorological monitoring site; and The period of time during which data are collected. Trinity performed an AERSURFACE analysis as well as other qualitative analyses to compare the land use and topography of the meteorological stations to the Stony Point Compressor Station. The analysis is reviewed in the following subsections Proximity of the Meteorological Station As described in the Guideline, the proximity of the meteorological data station and the application site is an important consideration in determining representativeness. The Dutchess County Airport, Orange County Airport, and Westchester County Airport are the three NWS meteorological stations that are located nearest to the Stony Point Station. Three stations also are relatively equidistant to Stony Point. The other NWS meteorological stations in New York and neighboring states are excluded on the basis of proximity alone Complexity of the Terrain The Guideline states that the complexity of the terrain is another important consideration in determining data representativeness. Regarding the three meteorological monitoring stations and the Stony Point Station, there are no significant terrain features (e.g., mountain ridge) between the sites or surrounding the individual locations, and the base elevations are similar, as shown in Table 3 1. As such, the wind flow at the four (4) sites will likely be similar. Table 3 1. Comparison of Site Elevations Site Elevation (m) Algonquin's Stony Point Station 86 Dutchess County Airport Met Station 49 Orange County Airport Met Station 111 Westchester County Airport Met Station 121 Although the terrain are generally comparable between the three meteorological stations, the three have distinctions worth noting: the Orange County Airport is located northwest of the facility on relatively flat terrain; the Westchester County Airport is located southeast of the facility on a plateau between the Hudson River and the ocean; and, the Dutchess County Airport is located five (5) km east of the river. Because the Stony Point Station is located four (4) km west of the river, the Dutchess County Airport meteorological station has more similar topographic settings to the facility than the two other airport meteorological stations Surface Characteristics The U.S. EPA released the AERSURFACE 5 program as an objective method for evaluating land use characteristics and their associated micrometeorological parameters for a given location. The AERSURFACE program is used in 5 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-3

238 the evaluation of potential NWS stations in the area. AERSURFACE uses 1992 National Land Cover Data (NLCD92) to create seasonal values of albedo, Bowen ratio, and surface roughness, across 12 directional sectors (e.g degrees), based on a 1 km radius out from the site. The seasonal parameters correspond to the calendar months in which they occur (i.e. winter values for December March), and the winter months assume no continuous snow cover. AERSURFACE comparisons between the Stony Point Station and the three airport meteorological stations indicate that albedo and Bowen ratios are relatively consistent. Surface roughness output from AERSURFACE is not comparable for any of the met stations to Stony Point. The NLCD92 values around the facility indicate that the land use around the facility in 1992 was over 80% mixed forest and deciduous forest, as shown in Figure 3 3. Based on a recent 2013 aerial photo, as shown in Figure 3 2, the land use around the facility includes more low impact residential and urban grasses, more in line with the land use around the three airport meteorological stations. Based on aerial views in Google Earth of the land use characteristics around the three airport meteorological stations, the land use at Dutchess County Airport seems the most similar to the land use at the Stony Point Station Data Quality Once a site is deemed representative, one of the key factors in determining suitability of a meteorological station s data is the quality and quantity of observations. Based on the Guideline definitions of representativeness, the three airport meteorological stations are suitable for the Stony Point Station. Since the data are coming from NWS stations, five years of quality data (at least 90% complete per parameter, per calendar quarter) are required. The data were collected during the period from January 1, 2009 to December 31, The five year period was evaluated to determine data completeness, and it was determined that 90% quarterly data capture was maintained. Table 3 2 presents a list of the parameters that were collected as well as a completeness summary for each value. Table 3 2. Comparison of Airport Meteorological Station Data Quality AERMET Surface Variables Dutchess Co. Airport Data Completeness (%) Orange Co. Airport Data Completeness (%) Westchester Co. Airport Data Completeness (%) PRCP SLVP PRES CLHT HZVS TMPD DPTP RHUM WDIR WSPD Surface Meteorological Dataset Selection While the three potential candidates compared well against the Guideline s representativeness criteria for proximity, topographical complexity, and data quality, the surface character at the Dutchess County Airport s Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-4

239 meteorological station most closely matched the surface character at the Stony Point Station. In consequence, the Dutchess County Airport s dataset was considered most representative and was, therefore, used for AERMET data processing Upper Air Sounding Data Concurrent upper air sounding data from the NWS station at the Albany County Airport (ALB) in Albany, New York was used in this assessment. The monitoring station is located approximately 168 km north of the Stony Point Station. Upper air meteorological conditions from the NWS site are reasonably representative of conditions at the Stony Point Station, as upper air parameters vary less with distance than surface area AERMET Data Processing Both the surface data and the upper air sounding data were processed using AERMET (version 14134), along with 1 minute Automated Surface Observing System (ASOS) wind data from the Dutchess County Airport, using the latest version of AERMINUTE (version 11325). The Stage 3 outputs from the AERMET processing consists of a surface data file (.sfc) and a vertical profile data file (.pfl) ready for input to AERMOD LAND USE ANALYSIS A land use analysis was conducted based upon examination of aerial photos of the Stony Point site and NLCD92 maps. As recommended by the Guideline, the land use within the total area circumscribed by a three (3) km radius circle about the facility was classified by the meteorological land use typing scheme proposed by Auer. 6 Figure 3 2 shows an aerial image of the area around the facility, and Figure 3 3 shows the same area using the United States Geological Survey (USGS) NLCD92 categories, which closely resemble Auer s land use types. Because land use types I1 (heavy industrial), I2 (light moderate industrial), C1 (commercial), R2 (new compact residential), and R3 (old compact residential), shown as shades of red in Figure 3 3, account for less than 50 percent of the total area, the area is classified as rural and rural dispersion coefficients are used in AERMOD. 6 Auer, Jr., A.H., 1978, Correlation of Land Use and Cover with Meteorological Anomalies, Journal of Applied Meteorology, 17 (5): Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-5

240 Figure 3 2. Aerial Image of 3 km Radius around Stony Point Station Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-6

241 Figure 3 3. NLCD92 Image of 3 km Radius around Stony Point Station Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-7

242 3.4. TERRAIN Source, building, and receptor elevations input to the model are based upon interpolation from the USGS s 1 arc second National Elevation Dataset (NED). The NED consists of arrays of regularly spaced elevations at 30 meter intervals. Elevation values assigned to model objects are interpolated using the AERMOD prep processor AERMAP (version 11103), based upon the maximum terrain elevation associated with the four NED points surrounding the specified object RECEPTOR GRID Ground level concentrations were calculated for receptors located on multiple Cartesian grids covering a region that extends 10 km from all edges of the contiguous facility fenceline. In consequence, only ambient air outside the fenceline was analyzed for the modeling analysis. Fenceline receptor spacing is set to 25 meters. Receptors are not placed within the facility s fenceline because Algonquin not only owns and controls the area but also precludes public access with the physical barrier of the contiguous fenceline. Outside of the fenceline, a receptor grid with 25 m spacing for up to 1 km, 100 m spacing between 1 and 2.5 km, 500 m spacing between 2.5 and 5 km, and 1,000 m spacing between 5 and 10 km was used, as shown in Figure 3 4. All receptors were projected using the UTM coordinate system in Zone 18 of the Northern Hemisphere, in NAD83. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-8

243 Figure 3 4. Receptor Grid Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-9

244 3.6. BUILDING WAKE EFFECT (DOWNWASH) The emission units at the facility were evaluated in terms of their proximity to nearby structures for the purpose of assessing the downwash of the plumes from those structures. The Guideline requires that stacks with a height less than the Good Engineering Practice (GEP) stack height should be further evaluated for determining air quality impacts associated with downwash. Because the stacks have a height less than the GEP stack height, further evaluation was required. The direction specific building dimensions that were used as input to the AERMOD model were calculated using the latest version of the Building Profile Input Program (BPIP) PRIME (version 04274). BPIP PRIME is designed to incorporate the concepts and procedures expressed in the GEP Technical Support document, the Building Downwash Guidance document, and other related documents. 7 The height of each building and the base elevation are provided in Table 3 3, and the position of each building is provided in Figure 1 2. Table 3 3. Building Dimensions Name Description Height Elevation (m) (m) AUX01 Auxiliary Building AUX02 Auxiliary Building CB1 Compressor Building CB2 Compressor Building CB3 Compressor Building CLR1 Gas Cooler CLR2 Gas Cooler CLR3 Gas Cooler CONT1 Control Building ELEC01 Electrical Building GAR01 Garage Building GEP STACK HEIGHT Section 123 of the Clean Air Act (CAA) defines GEP, with respect to stack heights, as the height necessary to ensure that emissions from the stack do not result in excessive concentrations of any air pollutant in the immediate vicinity of the source as a result of atmospheric downwash, eddies, or wakes which may be caused by the source itself, nearby structures, or terrain obstacles. Simply stated, GEP is a guideline criterion for determining stack height equal to the greater of: Where: H g H 1.5 ( L) OR 65 meters Hg = GEP stack height H = height of nearby structure L = lesser dimension, height or projected width, of nearby structure 7 U.S. EPA, Office of Air Quality Planning and Standards, Guidelines for Determination of Good Engineering Practice Stack Height (Technical Support Document for the Stack Height Regulations) (Revised), (Research Triangle Park, NC: U.S. EPA), EPA 450/ R, June Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-10

245 The maximum height of all stacks at the facility is below 65 meters; therefore, this requirement is met SOURCE PARAMETERS AND EMISSIONS The air dispersion modeling analysis accounts for emissions from both the proposed facility modifications and the existing emission units, as described in the minor NSR permit application. Table 3 4 identifies the vertical, non obstructed emission points, their descriptions, their locations, and their base elevation. These emission points, shown in Figure 3 5, reflect a UTM projection, in UTM Zone 18 in the Northern Hemisphere, in NAD83. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-11

246 Table 3 4. Emission Point Descriptions and Locations Emission Point Type Make Model Capacity Units STOTBC05 Turbine Solar Taurus S bhp STOTBC06 Turbine Solar Taurus S bhp STOTBC07 Turbine Solar Mars S bhp (ISO) STOTBC08 Turbine Solar Mars S bhp (ISO) STOTBC09 Turbine Solar Mars S bhp (ISO) Easting Northing Elevation (m) (m) (m) 582, ,566, , ,566, , ,566, , ,566, , ,566, STOENG01 Em Gen Waukesha VGF bhp 582, ,566, STOENG02 Em Gen Waukesha VGF bhp 582, ,566, STOHTR Boilers/Heaters State Industries SRX 50 NQRT 0.04 MMBtu/hr (output) Boilers/Heaters Carrier Corp. 58ED MMBtu/hr (output) Boilers/Heaters Carrier Corp. 58ED MMBtu/hr (output) 582, ,566, STOGHTR1 Boilers/Heaters Exterran N/A 0.25 MMBtu/hr (output) 582, ,566, STOGHTR2 Boilers/Heaters Cameron N/A 0.25 MMBtu/hr (output) 582, ,566, STOGHTR3 Boilers/Heaters Cameron N/A 0.5 MMBtu/hr (output) 582, ,566, Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-12

247 Figure 3 5. Emission Point Locations Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-13

248 To determine the maximum ambient concentrations due to varying operating conditions for the equipment, three operating scenarios were considered in the analysis, Normal (Scenario 1), Low Temperature (Scenario 2), and Annual Average (Scenario 3). These scenarios, which encapsulate the range of data associated with operational scenarios, capture the variations in stack exit temperature and flow potentially resulting from the varying loads, thus determining which load condition contributes to the worst dispersion. The modeled emission rates and stack parameters for each emission point listed above are shown in Tables 3 5 through 3 8. With respect to modeling 1 hour NO 2, the low temperature operation (Scenario 2) emissions, this scenario represent intermittent emissions and is therefore assessed in accordance with the US Environmental Protection Agency (USEPA s) March 1, 2011 memo entitled Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1 hour NO 2 National Ambient Air Quality Standard guidance. For NO 2 emission rates, Algonquin has assumed that low temperature operations will occur for 19 hours per year in the potential emission calculations. As such, the calculated weighted average hourly low temperature emission rate is the low temperature emission rate times 19/8760 (i.e., the fraction of the year that low temperature operation is assumed), with the normal emission rate occurring for the balance of the hours (8741/8760). This averaging technique applies to NO 2 emission rates only. Averaging was not employed for SO 2, PM, PM 10, PM 2.5 and CO, whose modeled emission rates represent maximum values for each scenario. Table 3 5. Modeled Stack Parameters for Project Equipment Emission Source ID Emission Source Scenario Turbine Stack Height (m) Exit Temperature (K) Exit Velocity (m/s) Stack Diameter (m) STOTBC Scenario Turbine STOTBC Scenario Turbine Scenario 2 STOTBC (1 hr NOx) Turbine STOTBC Scenario STOGTHR2 Gas Heater STOGTHR3 Gas Heater Emergency STOENG02 Generator Note that Turbines 7 through 9 stack parameters are identical and as thus not listed here by emissions unit. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-14

249 Table 3 6. Modeled Emission Rates for Project Equipment Emission Source ID Emission Source Scenario Turbine Scenario PM10 (lb/hr) PM2.5 (lb/hr) NOx (lb/hr) CO (lb/hr) SO2 (lb/hr) STOTBC Turbine Scenario STOTBC Turbine STOTBC Scenario 2 (NOx) 4.36 Turbine Scenario STOTBC STOGTHR2 Gas Heater STOGTHR3 Gas Heater Emergency STOENG02 Generator Note that Turbines 7 through 9 emission rates are identical and as thus not listed here by emissions unit. Table 3 7. Modeled Stack Parameters for Existing Equipment Emission Source ID Stack Height (m) Exit Temperature (K) Exit Velocity (m/s) Stack Diameter (m) STOTBC STOTBC STOENG STOHTR STOGHTR Table 3 8. Modeled Emission Rates for Existing Equipment Emission Source ID PM10 (lb/hr) PM2.5 (lb/hr) NOx (lb/hr) CO (lb/hr) SO2 (lb/hr) STOTBC STOTBC STOENG STOHTR STOGHTR NO2 MODELING OPTIONS Whereas modeled concentrations of PM 10, PM 2.5, SO 2, CO, and HCHO match the pollutant being emitted, NO X emissions are modeled differently because of how the pollutant behaves in the atmosphere and because of the NAAQS itself. When a fuel source (e.g., natural gas) is combusted, oxides of nitrogen (NO X ) are emitted, which Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-15

250 initially comprises of approximately 10% NO 2 and 90% nitrogen oxide (NO) for natural gas fired reciprocating internal combustion engines (RICE) like those at the Stony Point Station. 8 Over time due to photochemical reactions in the ambient atmosphere where NO converts to NO 2, the NO NO 2 ratio will settle out to the ambient atmospheric ratio, which is 80% NO 2 on a one hour basis and 75% NO 2 on an annual basis. Because the NAAQS is for the pollutant NO 2, only modeled concentrations of NO 2 should be compared to the NAAQS. To amend the discontinuity between the pollutant emissions (i.e., grams per second [g/s] of NO X ) and pollutant concentrations (i.e., micrograms per cubic meter [µg/m 3 ]), the Guideline outlines a three tiered approach. In the Tier 1 approach, all NO X emissions are assumed to be NO 2, so the total modeled concentrations are in terms of NO 2. If the Tier 1 modeled concentrations are greater than the NAAQS design values, the Tier 2 approach may be used. This approach is often called the Ambient Ratio Method (ARM) because the ambient atmospheric ratio is applied to modeled concentrations of NO X, where 80% are assumed to be NO 2 concentrations on a one hour basis and 75% are assumed on an annual basis. If Tier 2 modeled concentrations are greater than the NAAQS design values, the more refined Tier 3 approach (i.e., the Plume Volume Molar Ratio Method [PVMRM] or the Ozone Limiting Method [OLM]) may be used with consent from NYSDEC for non PSD air dispersion modeling. In keeping with the Guideline s approach, this air dispersion modeling assessment uses the Tier 2 approach (ARM). ARM was incorporated into the modeling analysis through use of the ARM control option within AERMOD. As such, the model effectively computes NO 2 concentrations resulting from stack emissions based on the 80% one hour and 75% annual NO 2 NO X ratios. The model then adds in the season hourly background monitored NO 2 concentrations to compute a total NO 2 concentration for comparison to the NAAQS. 8 U.S. EPA s NO2/NOX In-Stack Ratio (ISR) Database, Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 3-16

251 4. RESULTS This section summarizes the results of the dispersion modeling analyses and demonstrates that the modified facility does not cause or contribute to an exceedance of the NAAQS, SGC, or AGC. Concentration maps of the air quality impacts are shown in the following figures as listed below PM10 NAAQS ANALYSIS To demonstrate compliance with the NAAQS, the modeled impacts of facility sources were added to appropriate background concentrations and compared against the applicable NAAQS. The 24 hour PM 10 standard is not to be exceeded more than once per year on average in any consecutive 3 year period, meaning that generally the highest sixth high (H6H) modeled concentration over the full five years of meteorological data is compared against the NAAQS. Table 4 1 illustrates the results from the PM 10 NAAQS analyses, indicating that potential exceedances of the 24 hour NAAQS do not occur. Table hour PM 10 Modeled Results Averaging Period Scenario Year Easting (km) Northing (km) Modeled Conc. (µg/m 3 ) * Background Conc. (µg/m3) Total Conc. (µg/m3) NAAQS (µg/m 3 ) % of NAAQS 24 hour , % 24 hour , % 24 hour , % * H6H over five years 4.2. PM2.5 NAAQS ANALYSIS To demonstrate compliance with the NAAQS, the modeled impacts of facility sources were added to appropriate background concentrations and compared against the applicable NAAQS. The annual PM 10 standard is the arithmetic mean averaged over 3 years. Algonquin compared the arithmetic mean averaged over the full five years of meteorological data against the NAAQS. The 24 hour PM 2.5 standard is the 98 th percentile of concentrations in a given year, averaged over 3 years, meaning that generally the highest eight high (H8H) modeled concentration over the full five years of meteorological data is compared against the NAAQS. Table 4 2 illustrates the results from the PM 2.5 NAAQS analyses, indicating that potential exceedances of the 24 hour and Annual NAAQS do not occur. Figure 4 1 and 4 2 show the location of the maximum 24 hour (Scenario 2) and annual (Scenario 3) concentrations. The single greatest maximum impact, 2.89 µg/m 3 for 24 hour and 0.53 µg/m 3 for annual, is shown on each figure. Both maximum impacts are located in the nearfield, about 100 m from the plant. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 4-1

252 Figure hour PM 2.5 Impacts Scenario 2 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 4-2

253 Figure 4 2. Annual PM 2.5 Impacts Scenario 3 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 4-3

254 Table hour and Annual PM 2.5 Modeled Results Averaging Period Scenario Year Easting (km) Northing (km) Modeled Conc. (µg/m 3 ) * Background Conc. (µg/m3) Total Conc. (µg/m3) NAAQS (µg/m 3 ) 24 hour , % 24 hour , % 24 hour , % % of NAAQS Annual , % Annual , % * 5 year average of 98 th percentile 24 hour average concentrations for 24 hour PM2.5 * 5 year average of the annual arithmetic average concentration for annual PM NO2 NAAQS ANALYSIS To demonstrate compliance with the NAAQS, the modeled impacts of facility sources were added to appropriate background concentrations and compared against the applicable NAAQS. The annual NO 2 standard is the annual arithmetic mean. Therefore, Algonquin compared the annul arithmetic mean from each year of the meteorological data set against the NAAQS. The 1 hour NO 2 standard is the 98 th percentile of the annual distribution of daily maximum 1 hour concentrations over a 3 year average, meaning that the H8H modeled concentration for the full five years of meteorological data is compared against the NAAQS. Table 4 3 illustrates the results from the NO 2 NAAQS analyses, indicating that potential exceedances of the 1 hour and Annual NAAQS do not occur. Table hour and Annual NO 2 Modeled Results Averaging Period Scenario Year Easting (km) Northing (km) Modeled Conc. (µg/m 3 ) * Background Conc. (µg/m3) ** Total Conc. (µg/m3) NAAQS (µg/m 3 ) % of NAAQS 1 hour , % 1 hour , % 1 hour , % Annual , % Annual , % * 5 year average of 98 th percentile of the daily maximum 1 hour average (for 1 hour). Maximum annual average was used for annual standard. ** For the 1 hour runs, background concentrations from the Scranton monitor have already been included in the model output concentration. Figure 4 3 shows the maximum 1 hour (Scenario 2) NO 2 model output concentrations. The single greatest maximum impact, µg/m 3 is located in the nearfield, about 100 m from the plant. Since the seasonal background concentration for Scranton, PA (~77.8 µg/m 3 ) is also included in the model, the impact for the facility alone is approximately 80 µg/m 3. Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 4-4

255 Figure hr NO 2 Impacts Scenario 2 Algonquin Gas Transmission, LLC Modeling Report Trinity Consultants 4-5