FACILITY PROFILE

Irving Oil Refining G.P. Saint John Refinery

Prepared by: Authorizations Branch Department of Environment & Local Government December 2019

TABLE OF CONTENTS

BACKGROUND

PROCESS DESCRIPTION

AIR POLLUTION CONTROL

POTENTIAL AIR QUALITY CONTAMINANTS

POTENTIAL IMPACTS OF AIR EMISSIONS

AIR QUALITY COMPLIANCE AND ENFORCEMENT

PUBLIC OUTREACH

CONTACTS

BACKGROUND

The Refinery, built on a plot of farmland in 1959 in east Saint John, officially opened on July 20, 1960. At the time, the refinery was designed to process 38,500 barrels of crude oil per day (BPD). Two new process areas, constructed in 1976, resulted in the refinery becoming the largest in with a nameplate capacity of 266,000 BPD. The refinery has continued to improve unit and process efficiencies and currently has a reference rate of 313,000 barrels per day, offering a secure and reliable energy supply to customers across Eastern Canada and the Northeastern .

In order to prepare for the requirement for cleaner burning fuels, the availability of natural gas as well as potential changes in the supply of crude oils, Irving Oil Refining G.P. (formerly Irving Oil Limited) registered the Refinery Upgrade Project (1) under the Environmental Impact Assessment (EIA) Regulation in March of 1998. This project, which the Minister allowed to proceed under specific conditions (2) on August 13, 1998, involved the construction of eight new units, of which three were production units and five were environmental control units. These are discussed in the sections on Process Description and Air Pollution Control. By the end of 2001, all new units had been commissioned.

The Irving Oil Refining G.P. refinery produces a range of fuels for transportation (ultra- low sulphur gasoline, ultra-low sulphur diesel, jet fuel) and combustion applications (home heating oil, kerosene, Bunker C). Other fuels produced for use in more specialized combustion and transportation applications include butane and propane. The heaviest components of crude oil are used in asphalt, which is sold for paving.

PROCESS DESCRIPTION

The refinery consists of units for distillation, cracking, reforming (molecular rearrangement), product treating, steam and hydrogen production, sulphur recovery, and tanks for blending and product storage. Below are brief descriptions of the process operations:

Distillation

The purpose of crude oil refining is to convert the diverse mixture of petroleum hydrocarbons present in the crude oil, into component streams having the best use and marketability. Crude oil contains a mixture of hydrocarbons of various chemical compositions and boiling points as well as impurities, such as brine and sulphur and nitrogen compounds. This mixture contains a range of petroleum hydrocarbons from the lightest, methane, which is the primary constituent of natural gas, to the heaviest residues, with high molecular weights, that are used in paving asphalt. Between these are a series of hydrocarbons that are separated for use in gasoline, jet fuel, diesel fuel, home heating oil and heavy fuel oils.

The first step in the refining process, following removal of brine, is to separate the hydrocarbons present in the crude oil into distinct boiling ranges. Some of the separated products may be used directly in saleable products while others must be processed further in order to make the most of their inherent value and to meet product specifications.

The separation process, known as distillation, takes place in a distillation column as shown in Figure 1. The crude oil is first heated to temperatures above 700 °F after which it is fed to a distillation column containing a series of perforated trays. Due to differences in the boiling points of the hydrocarbons, the crude oil vapours condense on the trays at different levels within the distillation column. The lower boiling point hydrocarbons (heavier products) condense first and are withdrawn near the bottom of the column. As the crude oil vapours move up the column, progressively lighter fractions condense and are withdrawn. Those fractions that do not condense are withdrawn as a gas at the top of the column.

The heavy ends, those hydrocarbons that are too heavy to boil off in the first distillation column, collect in the bottom of the column and are withdrawn and sent to a second distillation column, which operates under a vacuum. Under vacuum, the hydrocarbons boil at lower temperatures and gas oils, which could not be vaporized in the first column, move up through the column and are separated out. The heaviest (bottom) products are used in asphalt. The separated gas oils are further processed in the cracking units as described under Cracking.

Figure 1: Schematic of Crude Oil Distillation Column

The refinery operates two crude oil distillation units: • Crude Unit No. 3 (146,000 BPD) constructed in 1976. • Crude Unit No. 4 (120,000 BPD) constructed in 1999 and commissioned in 2000.

Cracking

Following distillation, the gas oils, which represent approximately half of the crude, are broken into smaller molecules in processes referred to as cracking operations. Cracking employs a catalyst, which is a material that is used to promote a reaction but which is not consumed in the reaction. The catalyst is used either to speed up the reaction or to allow it to occur at a lower temperature, which renders the process more energy efficient. Following are the three cracking units at the refinery: • Residue Fluid Catalytic Cracking Unit (RFCCU) (85,000 BPD) where residual oil (high molecular weight "residual" oil) is cracked and can be separated into fractions including fuel gas, propane, propylene, butane, butylene, gasoline, diesel and decant oil. • Fluid Catalytic Cracking Unit (FCCU) (25,000 BPD) where vacuum gas oils are cracked and separated into fractions that form gasoline, diesel and liquefied petroleum gas (LPG); and • Visbreaker (20,000 BPD) where residue from the vacuum tower of the crude units is cracked at high temperatures to make gasoline and diesel fuels.

Molecular Rearrangement

Light molecules in the gasoline component streams can be rearranged to improve their properties as gasoline blending components. Reforming is normally carried out in the presence of hydrogen and a catalyst at temperatures of up to 1000 o F.

The refinery has five of these units, which perform specific operations as follows: • Butamer Unit (12,000 BPD) where normal butane is converted to isobutene. • Two Alkylation Units (8,000 BPD and 10,000 BPD) where iso-butane from other units is combined with butylene/normal butane mixture to make alkylate, a high octane, zero sulphur, low vapour pressure gasoline blending component; and • Rheniformer No. 1 (11,000 BPD) and Rheniformer No. 2 (28,000 BPD) where gasoline blending stocks are reformed to yield a higher-octane fuel.

Product Treating

Most refinery streams are treated to remove contaminants such as sulphur, organic acids, metals and surfactants that might be detrimental to engines or the environment. The refinery has five units that are used to treat product streams to remove contaminants: • Naphtha Hydrotreating Unit (NHT) (44,000 BPD) where sulphur is completely removed from the naphtha by reaction with hydrogen over a catalyst; • Hydrocracker (45,000 BPD) where heavy diesel and light cycle oil are desulphurized in the presence of hydrogen and a catalyst resulting in the production of ultra-low sulphur diesel products; • Hydrodesulphurizer (HDS) (56,000 BPD) where the sulphur in diesel blending components is converted to hydrogen sulphide by reacting with hydrogen over a catalyst; • Merox Plants (44,500 BPD) where mercaptans, which are odorous compounds, are removed from gasoline and jet fuels; and • CD-Tech Unit (58,000 BPD) where sulphur compounds are removed from cat- cracker gasoline in a two-stage process.

Steam Production

Many of the process units contain heat exchangers to recapture waste heat from process streams. Steam, produced in the refinery boilers and heat recovery steam generators (HRSGs), is used to provide power in turbines and ejectors, to heat processes and materials, and as part of the refining process.

The refinery currently has four boilers (1, 3, 5 and 6), and two HRSGs which burn refinery fuel gas. The HRSGs operated as stand-alone units until late 2004 when combustion turbines were commissioned as part of the Grandview Cogeneration Project. The combustion turbines generate up to 90 Megawatts (MW) of electricity that is sold to NB Power, a portion (approximately 65 MW) of which is re-sold to Irving Oil Refining G.P. for use in the refinery. The HRSGs now derive a significant portion of their heat input from waste heat generated by the combustion turbines, significantly increasing the efficiency of steam generation.

Hydrogen Production

Hydrogen, required as a feedstock for the hydrocracker and the diesel and naphtha hydrotreaters, is produced by a Hydrogen Plant where natural gas is the primary feed, but naphtha or butane may also be used, at high temperature and pressure and in the presence of a catalyst, is converted to hydrogen and carbon dioxide. Hydrogen is also produced as a by-product of the molecular rearrangement process.

A Hydrogen Recovery Unit recovers hydrogen from various process streams within the refinery.

Storage, Blending and Shipping

Approximately 15 to 20 different component streams are produced by the refinery. These products are stored in the tank field before being blended together in appropriate proportions to make various grades of gasoline, low-sulphur diesel, jet fuel, furnace oil and asphalt. The finished products are also stored in the refinery tank field prior to being shipped to customers via road, rail, and ship. The tank storage area contains 135 tanks storing crude oil, blending components and finished products. There are also a total of 8 spheres and 10 bullets for storing butane and propane.

AIR POLLUTION CONTROL

Owing to the complexity of the refinery, air pollution control is achieved through a variety of techniques including engineering design, task and unit specific control technologies, operating strategies and procedures, and programs having specific emission reduction goals. These are summarized in the following sub-sections.

Fuel Combustion Controls

Generally speaking, there is no air pollution control equipment on fuel combustion stacks (although there are some exceptions). Control is typically exercised by maximizing heat recovery at the process design stage through the choice of fuel and fuel sulphur levels and through optimizing furnace operating conditions. For example, process heaters for Crude Unit No. 4 were designed to be more than 90 percent efficient in terms of energy usage, which is reported to be 20 percent more energy efficient than the furnaces associated with Crude Unit No.1, which they replaced.

Sulphur Recovery

Refinery processing operations, where possible, are designed as closed cycle operations. This means that there are few emissions to the atmosphere. There are several reasons for this including safety, environmental protection, product recovery, and economics. The lightest fractions produced by each processing unit are stripped of their saleable components and the remaining gases, called sour gas (because of the hydrogen sulphide it contains) are sent to the Amine Sulphur Recovery Unit where the hydrogen sulphide is removed. The cleaned gas, known as refinery fuel gas or sweet gas, is used throughout the refinery to provide product heating with minimal emissions.

Recovered hydrogen sulphide gas is fed to the Sulphur Recovery Units/HATGU where the sulphur is recovered for sale to the fertilizer and pulp and paper industries. Some hydrogen sulphide gas is fed to the Sulphuric Acid Regeneration Unit where it is converted to sulphuric acid and used in the alkylation process. Approximately ninety nine percent of the sulphur is recovered in this process with the rest being emitted through the Sulphur Recovery Unit stacks as sulphur dioxide.

Water is used in a variety of processes within the refinery to clean and cool product streams. Water that comes into direct contact with petroleum products becomes contaminated and is likewise handled in a closed system. The sour water that results from these operations is cleaned of its impurities in the Sour Water Stripper where hydrogen sulphide and ammonia are removed. The recovered impurities are fed, along with the hydrogen sulphide from the Amine Recovery Unit, to the Sulphur Recovery Units AND hatgu.

The refinery presently has: • two Amine Sulphur Recovery Units (2450 mscfh recycle rate) and two Sour Water Stripping Units (7,600 BPD each). The second units in each case were added during the upgrade to provide additional sulphur extraction capability as well as redundancy for maintenance and other shutdown periods; • a Tail Gas Unit to remove additional sulphur from the Sulphur Recovery Units exhaust (tail) gas. The original unit (Sulphuric Acid Tail Gas Unit) installed during the upgrade did not operate as expected so the refinery was required to propose a solution. In 2008, a new unit was installed (the Hydrogenation Amine Tail Gas Unit or HATGU) which is achieving the desired sulphur recovery; • a Sulphuric Acid Regeneration Unit to regenerate spent sulphuric acid catalyst from the Alkylation Plants; and • two Sulphur Recovery Units (100 long tons per day each).

Flares

Process units are linked together in a system that allows for pressure relief of vessels being shut down for maintenance or due to upset conditions, such as a power interruption. The pressure is relieved by piping the excess product to one of three flares where the hydrocarbons are combusted at a safe distance from people and equipment. The flares are equipped with smokeless technology and steam assisted air dispersion equipment. The flare system tips were upgraded in 2004 to reduce noise when additional steam is directed to the flares. In addition, the No. 1 flare was upgraded during the fall 2007 turnaround and as a result of the newer technology employed, noise levels have been reduced.

FCCU Particulate Control

Particulate matter emissions from the FCCU are minimized by a series of cyclonic separators. Flue gases from the catalyst regenerator are passed through six sets of primary and secondary cyclones where centrifugal forces cause the particulate matter to move to the outside surface of the cyclones where they drop to the bottom and are removed. Flue gases from the secondary cyclones are sent to a third stage containing 80 high efficiency cyclones and then to a fourth stage high-efficiency cyclone where the majority of the remaining particulate is removed prior to it being released through the stack. During the 2017 Turnaround, the primary and secondary cyclones were replaced with an improved design to improve steady state performance. As the flue gas continues through each stage, the size and amount of the particles left in the stream decreases. Recovered catalyst is returned to the unit for re-use or recycled.

FCCU Carbon Monoxide Control

As part of the 1976 refinery expansion, a platinum combustion promoter was added to the regenerator. The promoter keeps the heat in the bottom of the regenerator where combustion of carbon monoxide to carbon dioxide is completed without hazard and reduces the concentration of the carbon monoxide emissions from approximately 10 to 0.01 percent.

Particulate Matter and Sulphur Dioxide Control on RFCCU

A Flue Gas Scrubber (FGS) was installed as part of the Refinery Upgrade Project to control emissions of particulate matter and sulphur dioxide from the RFCCU catalyst regeneration process.

Noise Control

Noise emissions from the refinery are controlled through the equipment selection process; a silencer to reduce noise on the FCCU was installed in 1995 in response to concerns from neighbours around the refinery. Noise mitigation is recognized as an integral part of the design process and noise level specifications were included in the upgrade project procurement process. In the fall of 2007, the refinery conducted a noise study as a requirement through their Approval to Operate. Although the results of the study showed noise to be within levels at their property line, it did help identify certain activities and units that contribute to slightly increased levels. As a result, several process and mechanical changes were made (such as the installation of silencers) to reduce intermittent noise levels.

Hydrogen Plant Carbon Dioxide Control

Primary sources of carbon dioxide within the refinery are from fuel combustion and from synthetic hydrogen production through steam/naphtha reforming. In order to reduce the refinery's emissions of carbon dioxide, recycle a contaminant emission and produce a saleable product, Irving Oil Refining G.P. entered into a joint venture with Praxair Canada Inc., and constructed a carbon dioxide liquefaction plant in the Grandview Industrial Park in 1997. Over half of the carbon dioxide emissions generated from the hydrogen plant are recovered and recycled as a food grade product.

Instrumentation and Stack Monitoring

The refinery re-instrumentation, carried out between 1991 and 1993, allowed for more frequent and precise control of all refinery processes. This improved control allows the optimization of refinery processes, which contributes markedly to energy efficiency and emission reductions. During re-instrumentation, a second fiber optic communication backbone was installed which provides a backup for the control system and allows the refinery to continue safe operation in the event that a portion of the control system becomes inoperable.

Stack emissions are monitored for a number of parameters. In some cases, the monitors provide direct measurements of contaminant concentrations such as the sulphur dioxide continuous emission monitors on the sulphur plant stacks. In other cases, such as the furnaces, boilers and the FCCU, process parameters including fuel flow, oxygen, and temperature are continuously measured. These measurements allow for optimal control of the process as well as, in combination with frequent fuel sulphur analysis, for the calculation of sulphur dioxide emissions.

Continuous Emission Monitors (CEMs) for sulphur dioxide and nitrogen oxides are operational on the Flue Gas Scrubber, the Tail Gas Unit and the Sulphuric Acid Regeneration Unit. During the construction of the Grandview Cogeneration Project, CEMs for sulphur dioxide and nitrogen oxides were installed on both HRSG's.

Operational Procedures

The refinery burns refinery fuel gas (sweet gas) to provide heat for the refining process. Of the existing total of 26 stacks, all but the FCCU emit flue gases from the combustion of refinery fuel gas.

Adherence to the Sulphur Dioxide Response Plan also contributes to reducing emissions and minimizing their impact. The operating approval requires the refinery to implement the plan, when ambient sulphur dioxide concentrations are above 8 parts per hundred million (pphm), which is approximately one half the maximum permissible 1-hour ground level concentrations of sulphur dioxide, at any one of five ambient monitors.

In order to conserve energy, process heaters and boilers are operated near stoichiometric (ideal) conditions, that is, the minimum amount of air required is used to enable complete combustion of the fuels. This operating objective has the benefit of minimizing emissions of all contaminants.

Shutdown, start-up and maintenance procedures are designed to minimize emissions. During planned shutdowns, units are steamed out and the resulting hydrocarbon mixture is burned in the flare(s) with clean fuels, such as propane or LPG, to minimize the hydrocarbon emissions. Wherever possible mechanical procedures are now employed to remove coke build-up on boiler tubes as opposed to the previous practice of slowly burning the coke out. Further, during maintenance of the sulphur plants or associated units, the refinery uses low sulphur crude to reduce the load on the operating sulphur recovery plant.

Product Quality

Product (fuel) quality affects emissions at the refinery level, during product distribution and in product usage. Changes to fuel quality are frequently driven by environmental and health concerns and often become requirements of national fuel regulations in Canada and the United States.

The Alkylation Unit (to reduce volatile organic compound (VOC) emissions), and Dehexanizer (for US reformulated gasoline) are process units that were installed between 1987 and 1994 as a result of new Canadian and US federal gasoline regulations aimed at reducing emissions from both gasoline storage and use. More recent federal environmental initiatives necessitated the upgrade to the Diesel Hydrodesulphurizer and the Hydrocracker in 1995, which allowed production of low sulphur diesel. This became a requirement in 1998 as a result of the Diesel Fuel Regulations (3). The Aromatics Saturation Unit was constructed in 1997-98 to reduce the benzene content in gasoline as required by the Benzene in Gasoline Regulations (4). The CD-Tech Unit installed in 2003 as part of the RFCCU provides enhanced capability to ensure that the Sulphur in Gasoline Regulations (5) are met. Irving Oil has also made infrastructure improvements such as new pipelines in preparation for adherence with the ultra-low sulphur diesel requirements mandated under the Sulphur in Diesel Fuel Regulations (6). In 2006, the hydrocracker was converted into a diesel treater to help meet these requirements.

The Ultra-Low Sulphur Gasoline Regulations had required an average gasoline sulphur content of 30 ppm or lower. In January 2017, Federal "Tier 3" gasoline regulations were implemented requiring an annual average gasoline sulphur content of 10 ppm. The refinery operations determined that gas desulphurization combined product sulphur of 15 ppm would be required in order to meet the Tier 3 regulation under various operating scenarios. An additional hydrotreating step was installed to the existing Gasoline Desulphurization Unit (GDS), which is a two-step hydrotreating unit, in order to meet a desired sulphur content of 15 ppm. Combining the remaining gasoline blend components with the hydrotreated stream allows the annual average combined sulphur in gasoline to meet the 10 ppm regulation.

Fugitive Emissions Programs

In 1993, the Irving began an annual program aimed at reducing its contribution to ground-level ozone in keeping with the Code of Practice for the Measurement and Control of Fugitive VOC Emissions from Equipment Leaks, October, 1993 (7) established by the Canadian Council of Ministers of the Environment (CCME). This program is comprised of the detection and repair of leaks (fugitive emissions) from specific process components such as pump seals, valves, flanges, vents, connectors, and compressor seals. The detection component of the program began in 1993. The program was expanded to include the repair of leaking components in 1995. When a repair cannot be made immediately, it is scheduled for the next available maintenance turnaround.

In addition, all Irving Oil Refining G.P. storage tanks are required to be maintained in accordance with the CCME Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from Aboveground Storage Tanks June 1995 (8), and the requirements of this guideline have been incorporated into an annual tank reliability program carried out by the refinery.

An odour study was completed throughout the previous Approval lifetime that identified odour issues that were addressed through various action items and process improvements.

POTENTIAL AIR QUALITY CONTAMINANTS

The refinery is situated in east Saint John and although it is in an industrial area, there are several residential areas within close proximity. Emissions from the refinery come from four main source areas: • Sulphur Block (includes two Sulphur Recovery Units, the Tail Gas Unit and the Sulphuric Acid Regeneration Unit) where, although 99 percent of the sulphur fed to the units is recovered, less than 1 percent is released to the atmosphere as sulphur dioxide as well as small amounts of nitrogen oxides, particulate matter and carbon dioxide. • Refinery Boilers and the No. 3 Crude Unit fired heaters where refinery fuel gas combustion results in the emission of sulphur dioxide, particulate matter, nitrogen oxides, carbon dioxide, and small amounts of carbon monoxide and hydrocarbons. • FCCU catalyst regenerator where sulphur dioxide, particulate matter, nitrogen oxides, carbon dioxide and small amounts of carbon monoxide and hydrocarbons are emitted. • FGS where nitrogen oxides, particulate matter, carbon dioxide and small amounts of sulphur dioxide and carbon monoxide are emitted.

Fugitive emissions can also have an effect on local air quality.

POTENTIAL IMPACTS OF AIR EMISSIONS

Acid Deposition

Emissions of sulphur dioxide and nitrogen oxides can be transformed in the atmosphere to acidic particles which ultimately fallout as acid deposition (acid rain is one way in which this deposition occurs). This deposition can occur far from the original source of the emissions. The majority of the acid deposition measured in New Brunswick is caused by emission sources in the US mid-west and central Canada. Generally speaking, acid deposition in New Brunswick has shown significant improvement through national and international efforts to reduce acid causing emissions, primarily through controlling emissions of sulphur dioxide.

The Department continues to report the acid disposition measurements in the Annual Air Quality Report.

Climate Change

When fossil fuels are burned it results in the generation of greenhouse gases (GHG) such as carbon dioxide (CO2) and methane (CH4), which are the main contributors to the problem of climate change. The Department has been working on a Climate Change Action Plan for several years and the Approval has a number of conditions related to reporting and improvements in greenhouse gas emissions.

Ground-Level Ozone

Ozone (O3) is a reactive, unstable form of oxygen. It is not emitted directly from stacks or exhaust pipes, but it is formed as a result of photochemical reactions between other pollutants, most importantly nitrogen oxides and volatile organic compounds (VOCs) such as solvent and gasoline vapours. Both stationary and mobile emissions sources contribute precursor pollutants that have the potential to result in the formation of ground-level ozone.

It has been estimated that 85 percent of ground-level ozone enters this region from the North Eastern United States, Central Canada and the American Mid-West (9). Elevated levels generally occur in the summer under very warm conditions when large stable air masses move up the eastern seaboard into the Fundy region. Although the contribution of local sources may pose an added stress to already deteriorating air quality conditions during such episodes, in general local sources are relatively minor contributors to ground- level ozone levels experienced in our region. Control programs in New Brunswick specifically for ground-level ozone are therefore not able to reduce ambient concentrations appreciably. Despite this, all measures which can reduce the emission of ozone precursors are promoted such as the refinery's Fugitive Emissions Program. Of particular interest are programs where multiple environmental benefits may be expected. For example, improving energy efficiency will reduce greenhouse gas emissions as well as nitrogen oxides and sulphur dioxide. Therefore, efficiency measures are favoured over measures exclusively targeting ground-level ozone.

AIR QUALITY COMPLIANCE AND ENFORCEMENT

Compliance and Enforcement options used by the Department of Environment are outlined in the Department's Compliance and Enforcement Policy (10). These may include but are not limited to: schedules of compliance, warnings, orders, and prosecutions. Although not specifically outlined in the Policy, it is also possible to amend approvals with more stringent conditions, both during its valid period or at the time of renewal, to address specific compliance issues or to improve the environmental impact of the facility. Most recently, a new Regulation under the Clean Air Act allows for the issuance of "administrative penalties" for minor violations as an alternative to traditionally-used enforcement options.

All sources of air emissions in the province are required to comply with the Clean Air Act and Air Quality Regulation. In addition to establishing ambient standards for contaminants in air, Section 3 of the Air Quality Regulation requires that "no person shall construct, modify or operate ... a source without applying for and obtaining an approval...” The refinery currently operates under Approval to Operate I-8902, issued July 1, 2015. The current Approval expires on June 30, 2020.

APPROVAL AMENDMENTS and PROJECTS

The Approval was amended twice during the lifetime of the Approval.

On November 15th, 2015 the Approval was amended to update the operation and maintenance of the ambient monitoring program that had been upgraded as well as adding general GHG conditions to the Approval to include reporting and submitting a Greenhouse Gas Management Plan.

On December 21, 2016 the Approval was amended to update the definition of Facility to add the Hydrogen Recovery Unit (Plant 426). This was not a new unit at the Facility; however, it was previously owned and operated by Air Liquid Canada and was acquisitioned by Irving Oil on December 31, 2016.

On April 4, 2017 an Approval to Construct the Tier 3 Gasoline Project was issued. This modification did not increase or change emissions at the refinery or increase the capacity.

Compliance with the Approval to Operate

Following are the key issues addressed in the Approval to Operate for Irving Oil Refining G.P. including comments on compliance with the associated conditions and actions taken to achieve compliance with these conditions. A summary of the key conditions are in italics.

Emergency Response and Reporting

Conditions 27 & 28 Notify the Department immediately (or the Coast Guard if not during business hours) following an environmental emergency and provide a written report within five business days of the incident.

The refinery continues to notify the Department of all environmental emergency incidents following the emergency response conditions in the approval. Environmental incidents of a non-emergency status are reported to the Department via email to the regional office as well as the approvals engineer.

Notable environmental emergencies during the lifetime of the Approval that impacted the neighbouring community included:

• On February 21, 2015 strong odours were reported from a broken seal in the internal floating roof of Tank 100. The tank was taken out of service for repairs. A temporary odour control unit was installed that included a caustic scrubber and carbon filter unit while it was being emptied and taken out of service.

• On November 12, 2017 an upset occurred in the FCCU where 21 metric tonnes of catalyst was released. Additional details are provided in the FCCU Condition 36 discussion.

• On June 17, 2018 a fuel oil release of 92-100 barrels occurred from the FCCU. Additional details are provided in the FCCU Condition 36 discussion.

• On October 8, 2018 a Hydrodesulphurization (HDS) unit fire occurred during the Turnaround period that impacted the HDS and the #2 Rheniformer. Ambient air quality monitoring in the surrounding area did not indicate any air quality concerns throughout the incident as the plume from the fire dispersed well in the direction of the Bay. Water used for fire suppression was directed to the industrial wastewater treatment unit, which was at normal operation and met all water quality limits.

Additional VOC testing was completed by a third-party consultant around the refinery to confirm there were no lingering air quality impacts to the environment.

A thorough investigation that included third-party consultants such as forensic fire investigators and metallurgists concluded the HDS reactor effluent line failed due to an area of localized pipe thinning as a result of internal corrosion. The units were rebuilt with a primary focus of increasing the corrosion resistance to prevent any recurrence of the problem.

The units were approved to be put back into service on June 28, 2019.

• On July 5th, 2019 a trip in the Residue Fluid Catalytic Cracking Unit (RFCCU) while the refinery was in a steam shortage caused a particularly noticeable flaring event with black smoke. The steam shortage occurred due to other units being down for planned and unplanned maintenance. A review was completed to assess preventive measures to reduce the chance or a recurrence of a steam shortage during a flaring event.

Condition 29 Provide the Department with training on the IOLGP Environmental Emergency Response Plan.

This training is scheduled for early 2020 at the refinery.

Limits

Condition 31 Limit annual emissions of sulphur dioxide to 5,200 tonnes per calendar year and 30 day rolling average emissions to 14.5 tonnes per day.

The refinery consistently has been below these limits during the period of the approval (see Table 1 for a summary of annual emissions). Over the past five years, average annual emissions of sulphur dioxide have remained well below the limit.

Table 1. Annual SO2 Emissions (Tonnes/year) SO2 2015 2016 2017 2018 Average Flue Gas Scrubber 114 123 116 96 112 FCCU 1051 1077 914 1,006 1012 Sulphur Block 637 474 539 562 553 Boilers, HRSGs, and Process Heaters 18 10 54 47 32 Flares 2 1 83 51 34 Total SO2 Emissions (tonnes/year) 1822 1685 1706 1762 1744

Prior to 2000, the had an annual sulphur dioxide emissions cap of 9,500 tonnes. In the EIA for the Refinery Upgrade Project, Irving Oil Refining G.P. proposed a reduction in the annual sulphur dioxide cap to 8,000 tonnes. This cap was included in their Approval to Operate issued in October 2000, and the cap was reduced again to 7,200 tonnes when the Approval was renewed in 2005 and to 5,500 tonnes in 2010. Sulphur dioxide emissions from the refinery have typically been stable and consistent as shown in Table 1.

Condition 32 Limit the annual emission of Sulphur compounds (SO2) from the Sulphur Block to less than 4,000 kg/day based on an annual average.

The refinery consistently has been below these limits during the period of the approval (see Table 2 for a summary of annual emissions).

Table 2. Average SO2 Emissions from the Sulphur Block Year Average SO2 (kg/day) 2015 1745 2016 1299 2017 1477 2018 1540

Condition 33 Limit the annual emission of Nitrogen Oxides (NO2) to less than 5,500 metric tonnes per year.

The refinery consistently has been below these limits during the period of the approval (see Table 3 for a summary of annual emissions). Nitrogen oxide emissions reported by the refinery are based on a variety of sources including stack tests, mass and energy balances, U.S. EPA emission factors and design data. The refinery has NOx CEMs on the FGS, SRUs, SARU and HRSGs.

Table 3. Annual NOx Emissions NOx 2015 2016 2017 2018 Average Flue Gas Scrubber 811 987 1227 787 953 FCCU 15 15 16 179 56 Sulphur Block 24 23 28 28 26 Boilers, HRSGs, and Process Heaters 1800 1813 1622 1540 1694 Flares 65 26 29 45 41 Total NOx Emissions (tonnes/year) 2715 2865 2923 2579 2771

Condition 34 Limit the annual point source emissions of particulate matter (PM) to less than 500 metric tonnes per year.

The refinery consistently has been below these limits during the period of the approval (see Table 4 for a summary of annual emissions).

Particulate matter emissions from the refinery are measured in two ways: material balances on the catalyst being used in the FCCU, and periodic stack tests. Fuel combustion, the FCCU catalyst regenerator stack and the FGS are the major sources of particulate matter emissions from the refinery.

Table 4. Annual PM Emissions PM 2015 2016 2017 2018 Average Flue Gas Scrubber 238 265 235 219 239 FCCU 105 93 104 80 96 Sulphur Block 2 2 2 3 2 Boilers, HRSGs, and Process Heaters 109 110 98 98 104 Flares 0 0 0 0 0 Total PM Emissions (tonnes/year) 454 471 439 400 441

Condition 35 Operate the Flue Gas Scrubber so that an emission rate of 50 mg/Nm3 particulate matter on a dry basis is achieved.

Annual performance tests conducted on the Flue Gas Scrubber indicate that particulate emissions were below the target emission rate except for the testing in July 2019. An additional source testing survey was completed on the flue gas scrubber in September 2019 to verify the previous results. The September 2019 testing demonstrated the particulate matter emission rate is below the target and no further work was required. Stack testing results are summarized in Table 5.

During the Fall Turnaround in 2018. the internal components in Flue Gas Scrubber were replaced for optimal performance.

Table 5. Source Testing Results for PM in the FGS Year Average PM (mg/Nm3)

2015 48.9

2016 41.0

2017 36.5

2018 41.8

2019 (July) 59.4

2019 (Sep) 34.1

Condition 36 Maintain particulate matter emissions from the fluidized catalytic cracking unit within an annual average limit of 300 kilograms per day during normal operation.

Particulate emissions in the Fluidized catalytic cracking unit (FCCU) are reported monthly based on a calculated rate that is very conservative. There have been several occasions when the estimate has been over 300 kg/day for the month, however, source testing results have consistently demonstrated the unit operates are within the limits.

Table 6. Source Testing Results for PM in the FCCU Year PM (kg/h) PM (kg/d)

Sep 2015 8.45 203

Feb 2016 9.7 233

Oct 2017 8.28 199 May 2018 6.14 147

July 2018 280

Nov 2018 124

Feb 2019 121

FCCU Upsets

During the 2017 Turnaround, upgrades were completed to the FCCU to improve catalyst particulate losses from the stack. On November 12, 2017, during start-up following the completed optimization project, an upset occurred where 21 metric tonnes of catalyst was released. The upset was caused by the modifications completed to the operating parameters.

Mitigative actions included developing a FCCU Catalyst Release dispersion model to provide an indication of the extent of the particulate deposition from the upset and assess environmental impacts to the surrounding area. The model can also assess normal operation emissions from the FCCU as well as any historical or future releases to the community. The model was used to prepare a response plan for future occurrences to determine affected areas for community notifications and mitigation. Irving Oil also performed 3 additional source testing events in 2018/19 to demonstrate the improvements in emissions from the FCCU optimization project.

The Approval Holder is required to provide actions taken to prevent the recurrence of the problem following an environmental emergency. For the catalyst release, the risk of a catalyst release during start up and shut down has been reduced with mitigation measures implemented to the operating parameters and controls and the full implementation of the optimization project.

On June 17, 2018 a fuel oil release occurred from the FCCU. An unplanned shutdown occurred on the unit. During the emergency shutdown process a supply feed valve was left partially open. While the unit was being restarted, 92-100 barrels of fuel oil was released due to a pressure release in the unit from the partially opened feed valve.

A dispersion model was completed to provide an indication of the extent of the liquid droplets deposition. It was estimated that 4-6 barrels (600 – 1000 litres) of fuel oil was released outside the refinery boundary. Soil samples were also taken at a location within the deposition zone. The samples showed trace amounts of total petroleum hydrocarbon (TPH) but were well within the RBCA Tier 1 Risk Base Screening Limit criteria for No. 6/lube oil and the Tier II Pathway Specific Screening Levels soil ingestion for No. 6/lube oil.

For preventative measures, piping was re-routed to ensure the feed valves remain closed when the unit trips.

In the two FCCU upset occurrences, both the DELG and the Department of Health were involved in the assessment of the impacts from the releases and approval of the mitigative actions.

Environmental Quality Limits

Condition 37 Limit ambient total reduced sulphur concentrations to 13 μg/m3 (9 ppb) as a 10 minute average and 7 μg/m3 (5 ppb) as a 24 hour average.

Reduced sulphur compounds are highly malodorous.

Three permanent ambient monitoring stations collect TRS data; Champlain Heights, Midwood Avenue and Forest Hills.

There are very few issues with TRS at the Champlain Heights and Forest Hills monitoring stations. The Midwood Avenue monitoring station has had a number of exceedances in the past few years; however, based on wind direction and refinery operations, they are not attributed to the refinery operations.

Condition 38 All activities at the facility related to the maintenance, decommissioning, construction and commissioning of any units are carried out in a manner to remain under these noise levels at the nearest receptor:

Time 90th Percentile Noise Limit 7:00 – 23:00 55 23:00 – 7:00 50

During the turnaround period, periodic noise monitoring is completed around the refinery to verify compliance with this condition and Condition 55 (noise monitoring).

Condition 39 The Refinery shall ensure that the sour-gas-to-sweet-gas by-pass valve remains closed and secured.

The valve is not capable of opening. It is locked with a numbered tag.

Condition 40 Maintain tanks storing volatile organic compounds in accordance with CCME guidelines "Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from Aboveground Storage Tanks" June 1995.

The refinery continues to perform tank inspection, maintenance and repair under their tank upgrade program. Irving Oil operates a Storage Tank Maintenance and Inspection Program which incorporates the requirements of the Canadian Council of Ministers of the Environment (CCME) "Environmental Guidelines for Controlling Emissions of Volatile Organic Compounds from Aboveground Storage Tanks". VOC emissions reported to the Department from this source have averaged approximately 113 Tonnes from 2015 to 2018.

EPISODE CONTROL

Condition 41 & 42 Maintain, and provide updates to the Director as they are prepared, a Sulphur Dioxide Response Plan, the purpose of which is to prevent exceedances of the maximum permissible ground-level concentrations of sulphur dioxide as per Schedule C of the Air Quality Regulation - Clean Air Act. Implement procedures as required to prevent exceedances of the maximum permissible ground-level concentrations of sulphur dioxide as per Schedule C of the Air Quality Regulation - Clean Air Act. This includes, but is not necessarily limited to, implementation of procedures invoked by the Irving Oil Refining G.P. Sulphur Dioxide Response Plan.

The refinery continues to implement the Sulphur Dioxide Response Plan when necessary. Sulphur dioxide concentrations are monitored 24 hours a day by operators within the Refinery Control Centre. If sulphur dioxide levels rise beyond pre-set limits at any one of the six monitors, the refinery takes action to reduce sulphur dioxide emissions in an effort to prevent exceedances of the regulated standards. The information received at the refinery consists of instantaneous sulphur dioxide concentrations, 5-minute rolling averages, and hourly and 24 hour sulphur dioxide averages.

Condition 43& 44 Ensure that, within sustainable limits, the feed to the HATGU is maximized so as to minimize sulphur dioxide emissions from the Sulphur Block.

Ensure that the gaseous effluent from the Amine Sulphur Recovery Units and the Sour Water Stripping Units, is directed, during normal operation, to the Sulphur Recovery Units and HATGU and/or the Sulphuric Acid Regeneration Unit, and during upset conditions to flare stacks No. 2 and/or No. 3, where upset means an inability to beneficially operate any of the components associated with the recovery of sulphur.

The HATGU is an integral part of the pollution control system and refinery operations. The SO2 emissions from the Sulphur block remain steady and well within the limits set out in Condition 32.

These conditions are in place to ensure Sulphur emissions are reduced as much as possible.

Condition 45 & 46 Conduct all Maintenance and Turnaround operations in a manner that minimizes emissions to the environment. All necessary and reasonable measures shall be taken to prevent impacts on the ambient environment including the creation of odorous or noisy emissions. Where Turnarounds are conducted the Approval Holder shall continue to conduct all operations in compliance with the Approval. The Approval Holder shall ensure that maintenance, decommissioning, construction and/or commissioning activities which are known or suspected to be noisy shall be limited to the hours between 07:00 and 23:00 Monday to Saturday. During periods when noisy activities are scheduled to be conducted either between the hours of 23:00 and 07:00, on Sunday or on Statutory Holidays, the Approval Holder shall provide the Department's Saint John Regional Office with advance notification of 2 days.

These conditions are in place to ensure periods of potentially increased noise levels are minimized as much as possible.

Condition 47 At least once per year conduct training for its staff with respect to the impacts of its operation (normal and abnormal) such that operation staff are aware of the potential for environmental impacts on the surrounding communities and are thereby better prepared to operate the Facility in a manner which is pro-active in identifying and mitigating impacts.

350 employees have been trained in an hour presentation in 2019 alone. Following this, all new employees will receive this training. This ensures that if there is an upset or issue, operational staff are aware of the notification protocols and potential environmental impacts.

TESTING AND MONITORING

Condition 49 The Approval Holder shall continuously monitor the flow rate, temperature, and sulphur dioxide concentrations from the Sulphur Recovery Units (SRUs), when flue gases are being directed through the SRU stacks. The Approval Holder shall also continuously monitor the flow rate, temperature, sulphur dioxide and nitrogen oxide concentrations from stacks associated with the Sulphuric Acid Regeneration Unit, the Flue Gas Scrubber and the Heat Recovery Steam Generators. Continuous Emission Monitors shall be maintained and performance tested in accordance with the "CONTINUOUS EMISSION MONITORING SYSTEM (CEMS) CODE" dated 1998 as published by Environmental Protection Environmental Service. Records of quality-assured data shall be maintained for a minimum of three years and made available in electronic or hard copy when requested by the Department.

The CEMS testing allows operators to effectively operate these units and minimize sulphur emissions. Condition 51 Continue to implement the Fugitive Volatile Organic Compound Emissions Measurement and Reduction Program in accordance with the "Environmental Code of Practice for the Measurement and Control of Fugitive Emissions from Equipment Leaks" as published by the Canadian Council of Ministers of the Environment (CCME), dated October, 1993.

The Leak Detection and Repair (LDAR) Program is completed annually at the refinery as per the current federal CCME Code of Practice. The program includes through identification, inspection, and analysis of all assessible components susceptible to volatile organic compounds (VOCs) leaks, including pumps, valves and their seals as well as flanges and their gaskets.

The LDAR Program helps to improve plant operation and reduces the release of VOCs. When leaks are identified, and as conditions allow, repairs are made to correct leaks.

Table 7 demonstrates the reduction in fugitive VOC emissions from the Detection and Maintenance Program. Year % Reduction in Fugitive Emissions 2015 33 2016 18 2017 17 2018 24

Condition 52 By September 30 of each year, investigate odour mitigation as it may be applied the tank farm and in particular the tanks, within the tank farm, that are or have been determined to have the greatest contribution to odorous impacts. As part of this on- going investigation the Approval Holder shall prepare annual reports that delineate the efforts to control odours from these source types, the results of these investigations, any mitigation to be permanently applied and any further investigations that are planned for the succeeding year. If the Approval Holder determines that there is a no more that can be done to mitigate odours, the report submitted is to reflect this conclusion.

The refinery has multiple programs and procedures in place to continue to mitigate odours from petroleum storage tanks. These include the Tank Life Extension Program, odour abatement systems, third party tank degassing systems and operation of tanks according to the CCME Environmental Guidelines for Controlling Emissions from Above Ground Storage Tanks.

Irving Oil maintains tanks through the Tank Life Extension Program. The Program objective is to achieve compliance with the American Petroleum Institute (API) 653 for above ground storage tanks. The maintenance work reduces VOC emissions and the potential associated odours.

The odour abatement system is used to mitigate odours in the community from the tank field. This system is on standby and is always available in the event that odours are detected.

During the 2016 Turnaround, the third-party degassing system was used at the refinery as a preventative measure. No concern calls were received in relation to odours during this turnaround period. The system has proven to be an effective way to minimize tank odours and VOCs and will be considered on a case-by-case basis during future turnarounds and tank maintenance.

Reid vapour pressure testing and tank temperatures are routinely monitored to maintain products within the CCME Guidelines to protect the integrity of internal floating rooves and seals.

Odour concern calls have reduced overall from this Approval period compared to the last Approval period. In 2015, there was a spike due to internal seal damage on the recovered oil tank. This tank was taken out of service and repairs were made to address this issue.

Conditions 53&54 Operate and maintain six sulphur dioxide ambient monitors in the east Saint John area and provide the refinery and the Department with real-time access to the information gathered by these monitors. Operate and maintain the appropriate hardware and software to provide the Facility with independent and real-time access to data.

As a condition of the amended air quality approval to operate, Irving Oil Refining G.P. is required to operate and maintain six ambient sulphur dioxide monitoring stations in east Saint John. These are located north of the refinery at the Silver Falls Irving, to the south- south east at the Irving Forest Products site in the Grandview Industrial Park, to the south at the blower building for the Irving Paper lagoon (known as Grandview West 1), Midwood Avenue, Champlain Heights subdivision and Forest Hills. The Department and the refinery both have rapid access to the information collected at the six monitoring stations.

The refinery is one of several significant sources of sulphur dioxide in the Saint John region and elevated ambient concentrations of sulphur dioxide may result from emissions from any or all of these sources. The exceedances of the sulphur dioxide ambient objectives at various monitoring locations in East Saint John are shown in Table 8. Exceedances have decreased dramatically since the installation of the HATGU and there have been only a few exceedances throughout the lifetime of the Approval.

Table 8: Exceedances of Maximum Permissible Ground Level Concentrations (Provincial Objectives) for SO2, East Saint John

Midwood Champlain Grandview Forest Hills Forest Silver Falls Avenue Heights West 1 Products

1-HR OBJECTIVE 2015 0 0 4 0 0 0 2016 0 0 1 1 0 0 2017 0 0 0 0 0 0 2018 0 0 0 3 0 0 2019 0 0 2 0 0 0 24-HR OBJECTIVE 2015 0 0 0 0 0 0 2016 0 0 0 0 0 0 2017 0 0 0 0 0 0 2018 0 0 0 0 0 0 2019 0 0 1 0 0 0

2015 The one-hour objective was exceeded on 4 occasions, all occurring at the Grandview West (Irving Oil Limited - IOL) monitoring station during January and February. Some operational issues were experienced with the Hydrogenation Amine Tail Gas Unit at IOL which were assessed and mitigated.

2016 The one-hour objective was exceeded once (one-hour duration) at the Grandview West station (Irving Oil Ltd.) on November 24th. This was associated with a short interruption of the operation of the sulphur plant at the refinery.

2019 The one-hour objective was exceeded twice (one-hour duration) on November 7th & 8th. th and the 24-hour objective was also exceeded Nov 8 . The SO2 exceedance source was identified as elevated SO2 emissions from the Sulfuric Acid Regeneration Unit (SARU) stack. On the 7th an unplanned maintenance outage occurred and on the 8th the SARU was in heat-up mode from a planned maintenance outage.

Condition 56 The Approval Holder shall continue to implement the Refinery Implementation Strategy Plan for Continuous Improvements in Odour Management and prepare an annual update to summarize the year's work to address odours and/or odour assessment.

In 2010 an Odour Impact Assessment Follow Up study was completed that included a strategy for continued improvements in odour mitigation initiatives and monitoring. The recommendations included:

• Continued focus on minimizing odour calls from flaring activity • Maintain community concern call program • Tank Maintenance and monitoring program • Utilizing refinery odour dispersion model

For flaring activity, efforts have focussed on optimizing the flare steam to fuel ratio to reduce concern calls and exceedances related to Total Reduced Sulphur (TRS) at the ambient monitoring stations. In 2014 reported concern calls for flaring was 29, compared to 2 in 2018. There were only 3 reported TRS Exceedances combined from 2015 to 2018.

The community concern call program and tank maintenance and monitoring program are described in other sections of the Facility Profile.

In 2013, an air dispersion model system of odour emissions generated by sources at the refinery was purchased. The refinery was modelled according to various refinery scenarios using weather station data in order to evaluate odour impacts to the surrounding neighbourhood.

The model was initially utilized to help identify areas for improvement within the refinery odour footprint and reduce concern calls. Since this initial period, the key sources of odours have been recognized and the model has been used less frequently. The model is available in the event that it might be required for future identification of odour sources.

Condition 57 Prior to February 01, 2016, develop an Ambient VOC Monitoring Plan to implement around the refinery boundary to better quantify the ambient air quality in relation to VOCs.

Irving Oil developed a VOC Fenceline Monitoring Study which was completed from June 2016 Through August 2017. Irving contracted a local engineering firm to prepare the plan and conduct the testing. Twelve sample locations were selected around the refinery perimeter with a total of 312 samples collected. The air contaminants monitored included benzene, 1,3-butadiene, ethylbenzene, toluene, and xylenes.

Irving Oil was the first refinery in Canada to conduct this type of study and selected the USEPA method 325A/B. This method is a regulatory requirement in the United States for oil refineries for fenceline monitoring. In this method, VOCs are collected from air using a diffusive passive sampler at specified locations around the facility boundary.

The US EPA fenceline benzene action level (limit) is 9ug/m3 and all measured results at the selected refinery fenceline sample locations were below the action level (limit) by a significant margin. Table 9 summarizes the results obtained from the study.

Table 9 Summary of Results from the VOC Fenceline Monitoring

Location Benzene 1,3-butadiene Ethylbenzene Toluene Xylenes (ug/m3) (ug/m3) (ug/m3) (ug/m3) (ug/m3) 1 0.82 <0.30 0.6 3.48 2.34 2 2.48 0.37 1.93 12.7 8.27 3 1.15 0.37 0.72 3.5 2.85 4 1.55 0.33 1.07 4.81 4.44 5 1.8 0.32 1.08 5.89 4.43 6 0.8 <0.30 <0.55 2.63 2.09 7 0.58 <0.30 <0.41 1.11 1.02 8 0.42 <0.30 <0.40 0.66 <0.80 9 0.42 <0.30 <0.50 1.9 1.53 10 0.35 <0.30 <0.41 0.75 <0.89 11 0.48 <0.30 <0.45 1.54 1.1 12 0.52 <0.30 <0.41 1.24 0.93 Annual Average Ambient 3 and 0.45* 0.3 and 2** 200 - - Guidelines (ug/m3) and 9

*Alberta guideline is 3 ug/m3, guideline is 0.45 ug/m3 ** guideline is 0.3 ug/m3 and Ontario guideline is 2 ug/m3 ***USEPA action rule is 9 ug/m3

REPORTING

Condition 63 Submit any updates to the Five-Year Source Testing Plan

Performance tests have been completed, as required based on the approved 5 Year Source Testing Plan.

General Monthly and annual reports are submitted, as required. Irving Oil Refining is in compliance with all report submission requirements. Additional information in the reports that have not been discussed in the Facility Profile are described below.

Condition 64 d) Summary of emissions of VOCs and benzene.

Table 10 demonstrates the annual VOC emissions and Table 11 demonstrates the annual Benzene emissions.

Table 10. Annual VOC Emissions (Tonnes)

Source 2015 2016 2017 2018

Fugitive emissions 86 149 147 151

Tank Farm 101 112 126 114

Fuel Distribution 77 78 75 73 Stack emissions 87 87 68 65

Spills 2 2 0 1

Flares 77 36 41 54

Wwtp 35 32 34 36

TOTAL 467 497 491 493

Table 11. Annual Benzene Emissions (Tonnes) Source 2015 2016 2017 2018

Fugitive Emissions 1.081 1.346 1.590 1.644

Tank Farm 0.445 0.399 0.334 0.301

Fuel Distribution 0.025 0.026 0.025 0.025

Stack emissions 0.000 0.000 0.000 0

Spills 0.001 0.001 0.000 0

Flares 0.000 0.000 0.000 0

Wwtp 0.611 0.545 0.580 0.621

TOTAL 2.162 2.317 2.528 2.591

VOC and Benzene emission have remained fairly consistent over the lifetime of the Approval.

Condition 64 e) the annual average, maximum and standard deviation of the daily mean concentrations of sulphur (expressed as hydrogen sulphide) in Refinery Fuel Gas.

Table 12. H2S Concentration in Fuel Gas

H2S 2015 2016 2017 2018

Average vol% 0.0013 0.0007 0.0007 0.0006

Maximum mean vol% 0.1050 0.0143 0.0711 0.0033

Standard deviation vol% 0.0068 0.0011 0.0037 0.0007

Refinery fuel gas composition has remained fairly consistent over the lifetime of the Approval.

Enforcement

Enforcement options used by the Department of Environment are outlined in the Department's Compliance and Enforcement Policy. These may include but are not limited to: schedules of compliance, verbal and written warnings, orders, and prosecutions. Although not specifically outlined in the Policy, it is also possible to amend approvals with more stringent conditions, both during its valid period or at the time of renewal, to address specific compliance issues or to improve the environmental impact of the facility. Most recently, a new Regulation under the Clean Air Act allows for the issuance of "administrative penalties" for minor violations as an alternative to traditionally used enforcement options.

During the life of the current Approval, Irving Oil Refinery G.P. Saint John Refinery has had no warnings or orders issued, nor have there been any prosecutions initiated by this agency during this period, related to air quality.

PUBLIC OUTREACH

Call Monitoring

The Irving Oil Refinery receives calls related to air quality, noise and other issues in east Saint John. The refinery has a call response procedure that must be followed by the person who receives the information. All calls are investigated and response is provided to those callers who identify themselves. Table shows the number of calls received by the refinery in the last 4 years.

Table 6. Concern calls received directly by the refinery Year Odour Noise Misc PM Total 2015 48 4 5 10 67 2016 21 14 4 0 39 2017 17 15 2 8 42 2018 11 19 98 0 128

Overall, the number of concern calls has decreased for the lifetime of the Approval compared to the previous one. The spikes are contributed to specific upsets at the Facility including: • Odour complaints in 2015 following an upset of the floating roof of Tank 100 in February and a mercaptan leak in September. • Miscellaneous concern calls in 2018 following the fuel gas oil release from the FCCU in June.

Community Outreach

Community Liaison Committee

The Irving Oil Community Liaison Committee was formed in 1998 as a requirement of the Environmental Impact Assessment Determination on the refinery Upgrade Project. The purpose of the committee was to liaise with stakeholders on issues associated with the Refinery Upgrade Project. The committee, made up of neighbours, government representatives, and employee team members, continues to operate even though the Upgrade Project has been completed. The Community Liaison Committee meets quarterly to discuss new projects and review developments on the refinery’s safety and environmental performance.

Neighbourhood Tours

Tours are conducted in the neighbourhood using a hybrid vehicle as required. The car was selected for its environmental performance and is used daily by members of the Environment Group to identify noise and/or odours that may be coming from the refinery. If an odour or noise is detected, the refinery is inspected for potential sources. Actions are promptly taken to mitigate or eliminate the concern.

The tour includes 18 test points, including points on Loch Lomond Road, Forest Hills Church, Creighton Avenue, and four locations along Grandview Avenue. The tour also includes inside the refinery. Areas such as the tank farms are inspected for harsh smells and wind direction.

Letters to Neighbours

Irving Oil keeps neighbours informed of events occurring at the refinery through letters that our either mailed or hand delivered to nearby homes. Topics discussed in these letters include maintenance turnarounds, construction notices, and project notifications.

For both the FCCU catalyst release and fuel gas release, letters were hand delivered to affected neighbours to provide information on the occurrence.

Neighbourly News

The Irving Oil Refinery delivers two newsletters annually to approximately six thousand residents around the Refinery. This newsletter serves as a link between the refinery and the neighbours to keep them up-to-date on the refinery's activities as well as their environmental initiatives. CONTACTS

For further information on the operation of the Irving Oil Refining G.P. refinery please contact:

Robyn McMullen Environment Manager Irving Oil Refining G.P. P.O. Box 1260 Saint John, New Brunswick E2L 4H6 Telephone: (506) 202-2361 Fax: (506) 202-4050 E-mail: [email protected]

Principal Contact, Saint John Region:

Patrick Stull Regional Director Region 4 Office Program Operations and Enforcement Branch NB Department of Environment & Local Government 8 Castle Street, P.O. Box 5001 Saint John, New Brunswick E2L 4Y9

Telephone: (506) 658-2558 Fax: (506) 658-3046 E-mail: [email protected]

For further information on this document, or on environmental regulations relating to air quality, please contact:

Sheryl Johnstone Senior Approvals Engineer Authorizations Branch New Brunswick Department of Environment & Local Government PO Box 6000, 20 McGloin St. , New Brunswick E3B 5H1

Telephone: (506) 444-4599 Fax: (506) 457-7805 E-mail: [email protected]

For comments or enquiries on the public participation process, please contact

Chandra Clowater Acting Manager Public Education, Stakeholder and Fist Nation Engagement Branch New Brunswick Department of Environment & Local Government PO Box 6000, 20 McGloin St. Fredericton, New Brunswick E3B 5H1

Telephone: (506) 457-7511 Fax: (506) 453-3843 E-mail: [email protected]