Issue Summary Sec # Response Change to Draft Reqs

Draft Directives 017 and 060 (released April 2018) Stakeholder Feedback and AER Response On April 24, 2018, the AER released, for public comment, draft Directives 017 and 060 to implement the Alberta government's Climate Leadership Plan objective of a 45% reduction in methane emissions from upstream oil and gas operations. During the public comment period, the AER received feedback from over 350 respondents, including industry, environmental nongovernment organizations, municipalities, investment firms, technology and emission control companies, research associations, and individual citizens. An overview of respondents can be found at the end of this table. The AER considered and reviewed in detail each comment received. Many of the comments raised similar issues or concerns. What follows is a summary of the issues and concerns raised and responses, as well as changes made to the draft requirements. Unless otherwise noted, the section numbers refer to Directive 060. Issue Summary Sec # Response Change to Draft Reqs GENERAL Many respondents supported reducing methane emissions by 45 per cent. Various comments were also in support of the draft directives, particularly of the approach taken, the distinction between new and existing facilities, pneumatic limits, the inclusion of enclosed combustors, the flexibility to adopt new technologies or innovative approaches to fugitive emissions detection, the fleet average for cold heavy oil production (CHOPs), and seeking equivalency with the federal government so that methane emissions are regulated provincially rather than federally. Some comments recommended two regulatory reviews one prior to December 31, 2020, and the second prior to December 31, 2022. 1.8 The comprehensive review is planned for no later than December 31, 2022, which is when most of the research projects will be completed and we will have sufficient reported emissions data to update our model. Prior to the review, we will meet annually with stakeholders to identify data gaps and to review reported data and research outcomes. As the requirements will only come into effect January 1, 2020, a December 31, 2020, review date would not allow sufficient time for data gathering and analysis in order to conduct a meaningful review. While there was broad support for the proposed regulatory review period, concerns were expressed about the process for regulatory review; in particular how transparent it would be. 1.8 The regulatory review process provides for an annual review of performance and other available data and also provides for multistakeholder consultation with the opportunity for stakeholders to make recommendations. Some respondents felt that the in-effect date for new sites would encourage operators to build more facilities or install equipment before January 1, 2022, so that they will be categorized as existing facilities and subject to less stringent requirements. A facility built before January 1, 2022, would still have to retrofit to meet the requirements that apply January 1, 2023. It would be more cost-effective to design facilities to meet the requirements instead of undertaking costly retrofits on existing facilities. Although the requirements for new facilities and equipment are generally more stringent than those for existing facilities and equipment, this difference allows us to meet the 45% reduction target while being cost effective. Page 1

Some comments were in support of the distinction between new and existing facilities and equipment. Others felt that this distinction was not justified and could undermine the methane reduction outcome. The distinction between new and existing facilities optimises the overall cost effectiveness of these requirements. Less-stringent retrofit requirements are applied to existing facilities, and more stringent design standards are applied to new facilities, which reduces the costs of complying with the requirements. Reducing the stringency of requirements that apply to existing facilities will not compromise the emissions reduction target because older facilities will be decommissioned and replaced with new facilities that are subject to more stringent requirements. Some respondents asked that "new facility" and "existing facility" be defined based on licensing date. The AER considered defining new and existing facility by licence date, but because the licence date is fixed, such a change would not capture expansions, relocations, and modifications. Basing requirements on first receipt or on production, installation, modification, and relocation as appropriate means that the requirements will still apply even as facilities change. Some respondents asked the AER to further clarify the scope of the regulations. Of particular interest was what midstream assets are in scope. D060 applies to all upstream petroleum industry wells and facilities. The proposed requirements apply to AER regulated upstream oil, gas, and bitumen wells; oil and gas facilities; gas plants; pipeline installations; storage facilities; and tank terminals (e.g., production and injection wells, batteries, and central processing facilities within thermal in situ oil sands schemes) The proposed requirements do not apply to AER-regulated facilities that are not related to oil, gas, or bitumen production (such as coal, shallow water wells, brine wells, NEB-regulated facilities, midstream meter stations, or midstream pipelines); oil sands mining schemes; processing plants for removing bitumen from oil sands at mines, including upgraders; refineries; rail-car loading facilities; downstream distribution pipelines; and downstream facilities. Page 2

Comments were received that the number of different in-effect dates in the draft requirements was confusing and needed to be simplified Commenters said that there are many important dates associated with these requirements and asked the AER to provide a "Table of Important Dates." To give operators enough time to comply with requirements, Directive 060 will be released before the directive in-effect date of January 1, 2020. Directive requirements such as the FEMP, the MRRCP, reporting requirements, the overall vent gas limit, and the new fuel flare and vent definitions take effect on January 1, 2020, with two exceptions: requirements for new equipment or facilities (January 1, 2022) and requirements for existing equipment and facilities (January 1, 2023). The AER has released a timeline with the final requirements. What is the in-effect date for the overall vent gas (OVG) limit? 8.3 The in-effect date for the OVG limit is the in-effect date for the requirements: January 1, 2020. Please note that s. 8.3.1 specifies exclusions in effect until January 1, 2023. The Directive 060 effective date has been changed to January 1 2020. Table 4 was updated to reflect this change of date. 8.1 (1) date deleted. 8.2.1 (1) date deleted. 8.6.2.1 date deleted. 8.6.2.1 (3) date deleted. 8.10.1 (1) date deleted. 8.10.3.1 (1) date deleted. Concerns were expressed that the requirements were developed without input from environmental and health groups The Government of Alberta directed the AER to develop the draft methane requirements using input from multiple stakeholder groups, including representatives of industry, environmental nongovernmental organizations, research organizations, Alberta Energy, and the Alberta Climate Change Office. The Government of Alberta's Climate Change Advisory Panel also engaged Albertans to recommend a plan for action. For more information please visit https://www.alberta.ca/climate-leadership-discussion.aspx The AER received a number of comments that were editorial in nature. Some comments were received requesting defined terms, like "site" be capitalized in the directives. A number of comments described early action that companies have taken to reduce their methane emissions in advance of the methane requirements coming into force. They asked that the AER take these actions into account when designing the requirements. Some comments asked why the AER didn't align their definition of non-routine venting with the federal definition. A number of comments were received asking the AER to define "duty holder," not only in section 8, but also in the definitions. AER directives follow the AER style guide. The editorial comments were reviewed and, where appropriate, the AER made the necessary edits. AER directives follow the long-established norms of standard English and the AER style guide, including avoiding unnecessary capitalization. The AER supports early action that has been taken to reduce venting and took this into account in its modelling and regulatory design. Companies that have taken early action to reduce venting will see a reduction in compliance costs where they have already met the limits specified in the requirements. The definition of nonroutine venting is not standardized across jurisdictions. The AER has maintained its existing definition of nonroutine venting, which is meant to prevent extensive venting that can pose risks to safety and the environment. 8 For ease of reference, the definition of "duty holder" in section 8 has been added to appendix 2. Added the definition of "duty holder" from section 8 to appendix 2 Page 3

Comments were received about the importance of the AER's compliance assurance procedures being transparent. We will use a variety of tools, such as data analysis, data audits, facility inspections, and regional surveys, to ensure that operators comply with the requirements. Dealing with noncompliances will be in accordance with Manual 013: Compliance and Enforcement Program and may include enforcement tools ranging from warnings and administrative penalties to orders imposing conditions and prosecution. Comments about the regulatory approach in the draft requirements included supporting the approach, advocating for more prescriptive or equipment-specific requirements, and advocating for more company-specific targets that would provide flexibility for operators to determine how reductions would be made. The AER's regulatory approach is a hybrid of prescriptive and outcome-based regulation. It was developed through a multistakeholder approach that allowed us to use the collective knowledge of a diverse range of people, including experts from industry, environmental nongovernmental organizations, research organizations, Alberta Energy, and the Alberta Climate Change Office. Multistakeholder committees provided technical input and advice in development of various regulatory approaches. We evaluated the different regulatory approaches using the following criteria: 1) Cost effective : targets sources, operators, and activities that maximize emission reductions at the lowest cost. 2) Adaptive : enables the AER and operators to accommodate technical innovation, operational constraints, socioeconomic contexts, and policy changes. 3) Operationally feasible : integrates with operators existing business models and processes. 4) Transparent and credible : demonstrates that performance objectives are met and governments are satisfied with the quality and rigour of requirements. In addition to the methane reduction requirements, the AER has measurement, monitoring, and reporting requirements that allow the AER to enforce and demonstrate industry-wide performance. A number of comments were received on Directive 017 and Directive 060 that were out of scope for the methane reduction requirements. These comments were collected for consideration in future updates to these directives. Page 4

RETROFITS AND COMPLIANCE Respondents commented that there should be fines for under-reporting methane emissions. The AER uses a variety of enforcement tools ranging from warnings and administrative penalties to orders imposing conditions and prosecutions, depending on the nature of the noncompliance. Some respondents highlighted the need for the AER to audit operator submissions to verify accuracy. Some respondents requested more detail about how the AER will assess for compliance with the requirements in section 8 and how noncompliances will be treated. The AER is using multiple tools, including audits, to assess and verify the accuracy of operator submissions. The AER will test each submission for compliance using the OneStop system. Further investigation and verification will involve data audits, regional sweeps, and field inspections. Responses to noncompliances will be based on several criteria, including the magnitude of the infraction and the operator history as outlined in the AER's Manual 013: Compliance and Enforcement and its Integrated Compliance Assurance Framework. Some respondents underlined that the AER needs to be able to verify the volume of reported emissions. The AER will use the monthly reported Petrinex data and the annual data reported in OneStop to automatically assess against the requirements to determine which facilities may be out of compliance and identify candidates for audit verification. The AER will also be randomly auditing reported data to verify accuracy. Some respondents recommended that enforcement mechanisms be expressly addressed in the regulations and noted that enforcement efficacy increases with prescriptive requirements. Some comments were critical of the crude bitumen fleet average (CBFA) approach; specifically the AER's ability to enforce compliance with this requirement. Compliance assurance was a key consideration when designing the methane reduction requirements. The AER has a number of enforcement mechanisms available to it under various different enactments that specfically address noncompliance with AER requirements. 8.5 The AER will enforce compliance of the crude bitumen fleet average by using monthly reported emissions to verify that operators are compliant. The AER has also increased how frequently operators must test gas-oil ratios for all facilities under the CBFA to address the fluctuating nature of CHOPS venting and to impose stricter testing requirements on lower-venting facilities. Some respondents requested more detail about how the AER will assess for compliance with the Methane Reduction Retrofit Compliance Plan (MRRCP). 8.1 The AER will audit MRRCPs for adherence with the requirements in section 8.1. The MRRCP will be used as a tool to ensure that operators are positioned to meet the requirements. The quality of MRRCPs will be used to develop risk profiles for data audits and to determine priority areas for regional sweeps. Some respondents requested that the text in section 8.1 make it clear that no update to the MRRCP will be required after 2023 when all retrofits and replacements should be complete. 8.1 The AER has revised section 8.1 to make this clear. Section 8.1(3) now indicates that the MRRCP must be updated annually until January 1, 2023. Page 5

Some respondents did not agree with the requirement to include the resources and budget to execute the MRRCP because it is proprietary and resource allocation is not necessarily correlated to compliance outcomes. 8.1 All information the AER receives is a matter of public record. The AER does not, however, intend to publish individual MRRCPs. Some respondents asked if the MRRCP will be submitted to the AER or if they will they remain with the duty holder. 8.1 Operators do not have to submit the MRRCP to the AER. However, the AER will begin auditing the plans on January 1, 2020, and operators must make the plan available to the AER upon request as of this date. Some respondents indicated that the June 1, 2019, deadline for the MRRCP does not leave enough time to gather information to outline the resources, budget, and schedule that will ensure compliance with the requirements of section 8.6. 8.1 The AER has extended the deadline to January 1, 2020, to give operators time to collect data and prepare meaningful documents. Changed the MRRCP deadline to January 1, 2020. MEASUREMENT, MONITORING, AND REPORTING A number of comments were received that methane emissions from the upstream oil and gas industry are significantly higher than what is currently reported. The AER acknowledges that there is a degree of uncertainty with current methane emission estimates in Alberta. Consequently, we included comprehensive measurement, monitoring, and reporting (MMR) requirements to enhance the coverage of reported methane emissions. The new MMR system will be used to ensure that reported emissions are consistent with facility and production type to increase accuracy. Comments were received regarding the need for strong, standardized measurement and reporting, along with further studies to reduce this uncertainty and improve the accuracy of methane emissions reporting. There were requests for transparency in the data collected on methane emissions. Specifically, some commenters would like publicly available data on a per site basis to determine if a site is in compliance. Others asked for industry performance information for benchmarking against other operators. Currently, National Inventory Report emissions for Alberta are based on reported information that is supplemented with estimates. New measurement monitoring and reporting requirements in Directives 060 and 017 will improve emissions estimates to reduce uncertainty and improve accuracy. Ongoing research and development projects to update and refine emission factors will also improve the quality of reported data. (See https://www.aer.ca/providing-information/by-topic/methane/reports-andstudies.) The AER will make methane emissions data available publicly, which may be in a similar format to the pipeline performance and water use performance reports available on the AER website. Concern was raised that where a transfer of ownership of a facility takes place late in a year, the records from the previous operator may not be transferred or be incomplete. 8.2 Holding the operator of record at the end of the calendar year responsible for reporting and record keeping is consistent with other AER directives. The OneStop system will retain annual methane emissions reports, keeping a record of previously submitted data. Page 6

Some respondents felt strongly that the measurement, monitoring, and reporting system needed to be improved by including detailed reporting by source venting category, the function and bleed rate of pneumatic devices, and taxation level reporting results, and by adjusting the economic calculations for vent gas conservation at heavy oil facilities. They also suggested the measurement, monitoring, and reporting system be continuously improved. Annual vented methane emissions will be reported in OneStop by equipment source. Record-keeping requirements for pneumatic devices have been expanded to include device type, and bleed rate can be determined from device make and model. Emissions will be reported in OneStop at the Facility ID level and can be verified using Petrinex reported data. Adjusting the economic calculations for vent gas is out of the scope of the methane project but has been noted. The AER will continue to update and improve the measurement, monitoring, and reporting system as methane requirements are implemented. Changed section 8.11 to address reporting. Some respondents were unclear whether emissions from pneumatic devices that are exempted from requirements to maintain safe operating conditions or to achieve a necessary response time should be included in the calculation for the OVG limit. 8.3 & 8.6.1.1 Prior to 2023, the OVG limit excludes emissions from equipment sources (pneumatic instruments and pumps, compressors, and glycol dehydrators). After 2023, all vent gas from pneumatic instruments and pumps should be included in the OVG limit. For both before and after 2023, all equipment categories are reported in the VENT code in Petrinex. This is clarified in the measurement, monitoring, and reporting manual. Some respondents said that 3.75 per cent of raw gas receipts in any year of operation is not sufficient, and many plants will be noncompliant when the new flare definition, with acid gas and dilution gas volumes included, takes effect. Comments were made that the methane requirements only use source level or "bottom-up" emissions quantification and reporting and asked if the requirements could accommodate atmospheric or "top-down" quantification methods and reporting. 5.2 The AER based the percentage of raw gas receipts per operating year on a sample set of data that indicated that 3.75 per cent will not significantly increase noncompliance. Acid gas volumes are excluded and a mechanism for their exclusion is being developed. Current top-down quantification methods are not able to distinguish whether a methane source is an upstream oil and gas source or a source outside the AER's regulatory mandate. The AER's quantification and reporting methodologies are aligned with other international standards that rely on bottom-up quantification. The AER supports new emission quantification methods and has put provisions in the fugitive emissions requirements for alternative fugitive monitoring programs so more top-down measurement and monitoring approaches for fugitive emissions can be applied when feasible. A comment was received that the compressor power rating should be included as one of the items in the annual methane emissions report 8.11 The AER has added to the record-keeping requirements. It is not a required reporting field. The compressor seal power rating has been added as a record keeping requirement in 8.11(1)(k)(ii) A number of comments were received that the definition of Facility ID in appendix 2 should not cross-reference the definition of Facility ID in Directive 047. For ease of reference, the Facility ID definition from Directive 047 has been added to appendix 2. Added definition of Facility ID to appendix 2 Page 7

Comments asked that the AER reinforce the use of ABCS codes by specifically stating in the Facility ID definition that ABCS codes are included. Directive 060 uses the Facility ID from Directive 047 for consistency. The measurement, monitoring, and reporting manual clarifies the use of ABCS codes. A number of comments expressed the need for changes to gas-to-oil ratio (GOR) test procedures to improve the accuracy and quality of reporting from cold heavy oil production with sand (CHOPS) operations. D060 s.8.5 & D017 s12.2.2 The AER is studying GOR testing procedures to inform any future regulatory changes needed to improve reporting. Commenters asked whether both volume and mass limits must be met for the DVG and OVG where limits are expressed by volume and mass. Some comments expressed a preference for direct emissions measurement rather that estimation methods. 8.3 & 8.4 A duty holder has the option to meet either the mass or the volume limit. 8.2 Both estimation and metering are forms of measurement. The AER requirements use estimation or metering depending on what is appropriate to balance accuracy and cost. The AER is also conducting studies to improve emission factors and testing methods. A number of comments were received requesting a measurement, monitoring, and reporting manual and expressing interest in participating in the manual's development. 8.2, 8.6 & 8.11 The AER has published the measurement, monitoring, and reporting manual to provide guidance for methane emissions estimation and reporting. Quantification methodologies and sample calculations for each source will be included. The manual was developed with input from consultants and other subject-matter experts. A commenter asked whether nonroutine venting is to be reported into OneStop. If so, more time will be needed for implementation. 8.3 Duty holders do not need to report nonroutine venting in OneStop. However, these volumes are included in Petrinex reporting. A commenter noted that there are no reporting requirements for the OVG limit in D060. 8.3 This information is captured through monthly reporting in Petrinex. Some commenters asked whether the records are required to be kept onsite. 8.11 No, the records do not have to be stored onsite. Any records requested by the AER must be submitted within 30 days of the request. A number of comments asked whether the operator physically operating the plant on December 31 or any active operator who operated the facility at some point during the year is responsible for methane emissions reporting. Commenters asked that industry be given the flexibility to report to the well level (UWI) rather than in aggregate at the Reporting Facility ID level (ABBT battery level). 8.2 The AER updated the directive to clearly define "operator of record" and made it clear that the operator of record as of December 31 is responsible for methane emissions reporting for that year. 8.2 Reporting venting and fugitive emissions at the UWI level is included in Petrinex but will not be possible in the OneStop reporting system. In section 8.2, "operator" is changed to "operator of record." In appendix 2, a definition for "operator of record" was added. A comment was received that a template is needed for the annual methane emissions report. 8.2 The OneStop reporting system provides a template for the annual methane emissions report. A commenter asked for the in-effect date for DVG reporting. 8.4.1 The DVG must be reported as part of the annual methane emissions report. The first annual methane emissions reporting is due June 1, 2020, for the 2019 reporting year. Page 8

Some comments indicated that it would be challenging to complete an inventory, particularly for the 2018 reporting year, and asked that compliance assurance be less stringent on inventories, particularly in the first years. 8.11 The AER expects compliance with all requirements and does not adjust how stringently they are enforced. Given the current in-effect dates, operators should have sufficient time to complete the inventories required to comply with requirements. A number of comments wanted more simplified measurement, monitoring, and reporting, while other comments requested more detailed measurement, monitoring, and reporting. 8.2 In developing its measurement, monitoring, and reporting requirements, the AER carefully considered what information would be needed for compliance assurance and performance measurement. Only essential information was included in the measurement, monitoring, and reporting requirements. A number of comments requested clarification of the record-keeping in-effect dates for various equipment-specific requirements. 8.11 To complete the annual methane emissions report, operators must have up-todate records. A commenter noted that when multiple facility codes could apply to a single site, the AER should provide guidance as to which facility code to select. As required in Directive 017, duty holders need to clearly delineate their sites and assets to reporting Facility IDs. More guidance is provided in the measurement, monitoring, and reporting manual. Several commenters asked for clarity on the definition of site. They felt that it is not clear if it refers to a geographical location, a Facility ID, a UWI, or something else. They asked what happens if a facility is noncompliant with a limit at a Facility ID level, but compliant on a geographic basis. Site is defined in. To enforce compliance, the AER will identify high risk sites by utilizing risk rules and will determine non-compliances through the investigation of high risk submissions at the Facility ID level. A commenter asked how the AER plans to manage electronic reporting. 8.2 Within OneStop, the AER is developing a new reporting system to accept methane emissions information by source as well as other defined attributes that support compliance and performance management. Training and more information on OneStop will be made available. VENTING Comments were made about how the new limits in section 8 work with the timelines and limits for combined conservation, flaring, and venting in section 2. Some commenters asked that the source-specific exceptions to the OVG limit end on January 1, 2022, instead of on January 1, 2023. 2 The limits and timelines in section 2 remain in effect. However, venting may not exceed the limits in section 8 when calculating the combined flared and vented volumes. This has been made clear in section 2. 8.6 The source-specific exception date was set to provide industry with sufficient time to work out operational issues associated with installing new equipment. Page 9

Comments were received that venting from in situ facilities should not be covered by the requirements because in situ facilities are already subject to limits and restrictions through AER scheme approvals, facility licences, and EPEA approvals. They also noted that the only significant venting from these facilities would result from upset conditions (which occur infrequently at in situ facilities) that could result in venting a volume of gas that exceeds the limits. 8.3 All sites and facilities must be designed and operated to comply with the venting requirements in Directive 060. Section 8.5 of the directive states that thermal in situ schemes and operations are '... excluded from the vent gas limits for crude bitumen batteries. Upset conditions are not exempt from the venting requirements in Directive 060 because they can be routed to control devices. Please note that in situ facilities that are over the volumetric limit in an upset condition may still be under the mass limit because OVG may be stated in both volumetric and mass terms. A commenter pointed out that operators could exceed a vent-gas volume limit but not exceed the associated vent-gas mass of methane limit when there are low concentrations of methane in the vent gas stream. The significance of this noncompliance risk should be highlighted in Directive 060 to help reduce false noncompliances and the associated administrative burden to both the regulator and industry. A comment requested that the AER allow for a special exception for vent-gas capture and use via catadyne heaters. While they are not as efficient as the Directive 060 requirements, catadyne heaters are a cost-effective methane abatement tool. Some commenters felt that a maximum vent rate should apply to all sites that are using the crude bitumen fleet average (CBFA) to impose an upper threshold on any single site's venting. Several comments noted that operations in the Peace River area are excluded from the CBFA. They argue that operators in the area have made significant efforts to reduce emissions and odours in this area and fairness demands that these efforts be included in the CBFA. 8.3 Operators have the option to provide methane emissions in mass rather than volume and to use the actual methane composition when reporting volumes. 8.7 Catadyne heaters are not considered a control device under Directive 060. Vent gas directed to a catadyne heater should be reported as fuel gas. 8.5 The OVG limit acts as an upper threshold for venting at all sites, including those using the CBFA. 8.5 Directive 084 is an area-based regulation dealing specifically with odour issues, whereas Directive 060 is province-wide and addresses methane emissions. The inclusion of Directive 084 areas into the CBFA could allow for greater venting in areas outside of the Peace River area. Additionally, only a small number of companies operate in the Peace River area and AER modelling indicates that operators with sites excluded because of the Directive 084 exclusion would not bear an undue burden as compared to other companies. Several commenters felt that the CBFA will allow operators of crude-bitumen sites to increase emissions. A comment was received that the CBFA should be used for all sites, not just for crude bitumen batteries, for consistency and to not unduly harm natural gas and conventional light oil production. The comment argues that it is inequitable for one segment of the industry to have different rules. 8.5 The CBFA requires operators to reduce emissions while still providing flexibility to address the limit as they determine. 8.5 Emissions from crude bitumen sites come primarily from venting, which allows the AER to monitor these sites more closely and ensure that the fleet average is met. Emissions from other site types are more varied and do not lend themselves as readily to a fleet average approach. Page 10

Several comments asked that the AER clarify how fleets are to be grouped. 8.5 As indicated in section 8.5 (1), the fleet average is calculated based on the venting from all crude bitumen batteries of a duty holder that reported production or venting in a month. A comment asked that in cases where there are multiple licences at a single site, does each licence have an OVG limit? 8.3 No. Multiple licences at a single site do not increase the single OVG limit at a site. The OVG limit is a site limit, not a Facility ID limit. A comment asked that when there is a reference to controlled liquid hydrocarbon tanks, is there a size limitation or is it intended to encompass any hydrocarbon tank (including small diesel storage and large crude oil tanks)? A comment was made that "venting," as shown in figure 10, does not include all types of venting. Table 5 Figure 10 The reference to controlled liquid hydrocarbon tanks is meant to encompass any hydrocarbon tank with emissions being routed to a control device such as a flare or a vapour recovery unit (VRU). It is not typical for a diesel storage tank to be routed to flare or VRU. Figure 10 is not a requirement and is only included to add clarity. Fundamentally, if an activity is regulated under Directive 060 and methane is emitted to atmosphere, it is subject to the requirements of Directive 060. A commenter felt that the statement, "the AER recommends that duty holders eliminate all routing venting," is vague and potentially provides scope for the AER to require the elimination of all routine venting. 8.0 This is a recommendation, not a requirement. A commenter felt that there should be a requirement that duty holders have a plan in place for existing facilities to meet the defined vent gas (DVG) limit associated with that facility. 8.4 We encourage operators to have a plan in place to meet the DVG limit, but we do not require one because it is up to operators to determine control or process changes that are needed to meet compliance when the DVG limit comes into force. The AER is focussing our planning efforts on equipment retrofit and replacement requirements because these require longer lead times for procurement and installation. We received some comments that the DVG limit is too low and will overshoot the 45% reduction target, putting an undue burden on the Alberta oil and gas industry. Others felt that the DVG limit was too high and should be lowered to ensure that the reduction target is met. 8.4 Vent gas limits were determined on a portfolio basis. This means that some vent gas sources may reduce methane venting by more than the overall 45% target and some sources may reduce methane venting by less than the target so long as the overall 45% reduction target is reached. The source reductions are determined by several factors, including cost, reporting complexity, and certainty of reductions. A commenter asked why vent gas from pneumatic devices, compressor seals, and glycol dehydrators were excluded from the DVG limit. 8.4 They are excluded because limits specific to these types of equipment are in place (see section 8.6). Page 11

Several comments noted that section 8.3 ends with, "the duty holder must comply with the vent gas limits specified below," but that no list of limits was provided. Some commenters asked the AER to provide scenario-based examples to help illustrate the difference between OVG limit and DVG limit applications. 8.3 The AER has revised this text to aid in clarity. The various vent gas limits are located in the Equipment-Specific Vent Gas Limits section (section 8.6). 8.3 The measurement, monitoring, and reporting manual has a sample calculation outlining the difference between the OVG limit and the DVG limit. Updated text in 8.3 1) to clarify where the vent gas limits can be found Some comments noted that DVG and "other routine sources" appear to be the same thing and asked the AER to add DVG to figure 10 to make this clear. A commenter noted that vent limits will be applied on a monthly basis and that, as the AER is currently enforcing vent limits on a three-month rolling average, suggested that this practice continue. They note that sites that routinely exceed vent limits will need to be addressed in either case. Figure 10 Figure 10 is for illustrative purposes only and does not include limits. Routine and nonroutine are defined terms and not limits per se. DVG is the name of the limit associated with some (but not all) of the items covered by the "routine" definition. 8.3 The AER does not enforce vent limits on a three-month rolling average basis. The AER is using a monthly limit to increase certainty that the methane reduction targets are met. Several commenters recommended that due to normal fluctuations in operating conditions, the compliance enforcement of the CBFA be done on a three-month rolling average vent rate, not on a one-month vent rate. This would accommodate normal operational fluctuations, particularly around start-up and interventions. 8.5.1 In the case of crude bitumen facilities, the fleet-average approach provides flexibility for fluctuations in normal operating conditions; therefore, additional flexibility is not required. A three-month rolling average approach would limit the AER's ability to meet the reduction target. Comments were received stating that the OVG limit would allow existing sites to vent vast amounts of gas from tanks and other equipment with little constraint and that an approach to venting that allows those emissions to increase is more lax than in other jurisdictions and is not credible. 8.3 The OVG limit acts as a ceiling on all venting both routine and nonroutine and is in line with existing limits on venting. In addition to the OVG limit, there are additional vent-gas specific limits that will further reduce venting from tanks and other equipment. Taken together, these requirements will reduce venting and help achieve the methane reduction target. A commenter noted that OVG limit is applied regardless of facility size and operation type and argued that it should be increased for larger facilities. 8.3 Larger facilities typically have controls in place to limit venting. The AER has consistently applied a 500 m 3 /month venting limit to all facilities. A large number of comments were received asking for more clarity or suggesting changes to table 4. Table 4 Table 4 is intended to be used as a summary and the requirements are contained in the sections that follow and has been updated to improve clarity. Table 4 has been updated to improve clarity. PNEUMATICS Some respondents were unclear if the vent rate or actuation requirements for instruments installed before January 1, 2022, apply to the 10% of venting instruments allowed if installed after January 1, 2022. 8.6.1 In the final requirements, the language has been changed to make it clear that the vent rate and actuation requirements apply to both instruments installed before January 1, 2022, and to those installed after. Updated text in 8.6.1 Page 12

Some respondents highlighted that the 10% set aside for venting pneumatics requires operators to retain an inventory of instruments on an ongoing basis, which increases administrative burden. 8.6.1 Duty holders only need to inventory as many instruments as required to support the calculation of any venting instruments up to 10%. Additionally, operators are only required to maintain an inventory of instruments, not create a new one every year. Some respondents indicated that time-based actuation requirements should account for production variations or recharge run times. 8.6.1.4 The AER understands that the actuation frequency of level controllers operating at well sites is related to production and well recharge. Level controllers can be installed in multiple different configurations and not only at wells. The AER has clarified that actuation frequency should be measured under normal operating conditions. Reworded 8.6.1 to clarify that actuation frequency is to be measured during normal operating conditions Some respondents indicated that removing exemptions and applying vent-rate requirements for devices installed before January 1, 2023, would be a clearer approach. 8.6.1 The approach selected by the AER is intended to optimize flexibility for operators and expand emissions-reduction coverage in low abatement cost source categories. Moving to vent-rate-based device requirements would require stricter requirements in other source categories to compensate for a loss in reductions. Some respondents asked that an economic threshold be applied for retrofits that may be uneconomic at some sites. 8.6.1.4 The AER considered a variety of approaches to address economic considerations; however, these would be administratively burdensome and would increase the overall cost of regulation. The Government of Alberta (GoA) has offset credit programs in place to ease the economic burden of pneumatic requirements. Some respondents asked why propane-driven pneumatic devices were exempted from the requirements. 8.6.1 Propane-driven pneumatic devices are now included in the requirements. The AER does not want to incentivize operators to install propane-driven pneumatic devices, which still emit gas, over nonemitting technologies. Removed exception for propanedriven pneumatic devices in section 8.6.1 Some respondents were concerned that they would be required to annually inventory their sites to update their pneumatic inventory to meet the recordkeeping requirements in 8.11(1)(c). Some respondents requested that additional wording be added to suggest that operators go beyond the requirements and use no-bleed pneumatic solutions wherever possible. 8.11 The AER reviewed the wording in 8.11 to ensure that it is clear that operators do not need to visit each site on an annual basis to inventory pneumatics so long as an accurate inventory is maintained. 8.6.1 Section 8 includes a statement recommending duty-holders to eliminate all routine venting. The definition of low-vent alternative was deleted and the language has been updated to not exclude non-emitting technologies as acceptable alternatives. "Annual" has been removed from the reference to "inventories" in section 8.11 (1) (c) Low-vent alternative deleted Some respondents asked what requirements apply to chemical injection pumps for sites constructed before 2022. 8.6.1.4 Chemical injection pumps for sites constructed before 2022 are covered under the OVG limit beyond 2023. Some respondents requested that safety exemptions be expanded to include devices installed after 2022. 8.6.1.1 The AER reviewed the wording in 8.6.1 to ensure that it is clear that safety and response time exemptions are applicable for devices installed after 2022. Updated sections 8.6.1 Page 13

Some respondents suggested that the wording in section 8.6.1(4)(a) and (b) more explicitly state that low/no-vent alternatives, or controls, are acceptable options to allow for more flexibility. 8.6.1 (4) The AER has removed the reference to low-vent alternative and added language to clarify that zero-venting options will apply. Updated 8.6. to use actuation frequency rather than "low vent." Also, deleted "low-vent alternative" from appendix 2. COMPRESSORS One commenter noted that mandating compressor packing vent metering with an uncertainty requirement that lines up with Directive 017 section 1.7.2 is too stringent at 5% single-point uncertainty (especially for such a low-flow-rate gas stream). A comment was made that the costs to reduce emissions from compressors may outweigh the benefits and that the AER should consider exempting them. 8.6.2 In section 8.6.2(2), the maximum single-point test uncertainty has been specified at +/- 10% based on an AER testing study for flows over 0.1 m 3 /hr with no stringency for flows below that volume. 8.6.2 Compressors are a material source of emissions in the upstream oil and gas industry. Measurement activities and costs to reduce emissions from compressors can be coordinated with fugitive-emissions surveys or routine maintenance activities. Additionally, to reduce costs, the AER has included a fleet average for reciprocating compressor venting to give operators the freedom to determine where to incur costs. Changed compressor seal testing uncertainty in section 8.6.2 (2) Some commenters asked the AER to define "fleet." 8.6.2 The reciprocating compressor seal fleet is expressly defined in section 8.6.2.2 as the duty holder s reciprocating compressors that are rated 75 kw or more, pressurized for more than 450 hours per calendar year, and either a) were installed before January 1, 2022, or b) were installed on or after January 1, 2022, and have fewer than four throws Changed 8.6.2.2 2) to define RCS fleet. A commenter asked the AER to provide clarity on compressor "pressurized hours" and asked whether the AER would allow the use of "unit operating hours" as a proxy. The directive uses the term "throw," which appears to equate to "cylinder." A commenter asked if the AER would consider replacing "throw" with "cylinder" for consistency with the federal requirements. 8.6.2 We expect pressurized hours to align with operating hours. In cases where they don't align, operators are expected to track pressurized hours. 8.6.2 The AER considered replacing throw with cylinder ; however, as defined in the directive, a throw contains the entire rod packing seal system and not just the cylinder. The term "throw" is more inclusive of the potential vent sources that need to be considered. Commenters asked how a "deactivated throw" should be addressed in the fleet average calculation. Some commenters noted that vent gas control systems for reciprocating compressors may cause backpressure to the crankcase and result in methane venting. And they asked for exceptions for certain makes and models where this will be an issue. 8.6.2 Throws that are not pressurized (e.g., a deactivated throw) have no weight in the fleet average (time pressurized = 0). 8.6.2 The AER has updated the requirements so that operators are not required to tie-in and control compressor crankcase vents. The exception can be found in section 8.6.2.2. Changed the reciprocating compressor seal description in section 8.6.2.2 Page 14

A commenter noted that many reciprocating compressors between 0.75 and 1 MW are being used in the upstream oil and gas sector in Alberta and that the provincial requirements for these compressors are much less stringent than the federal requirements. 8.6.2 The AER requirements capture compressors that are rated higher than 75 kw (0.75 MW) and operate for more than 450 hours per calendar year. The AER acknowledges that the federal reciprocating compressor requirements are different; however, the overall approach of these regulations achieves Alberta's methane reduction target. Some respondents disagreed with the compressor fleet-average approach, arguing that it is essentially unenforceable. They argue that emissions-monitoring technologies have not advanced sufficiently and are not cost-effective enough for it to be possible for the AER to monitor each site individually. This would leave the proposed regulatory methodology open to abuse. They concluded that because the AER can in no way confirm that individual facilities are complying with the proposed regulations, the fleet-average approach should be avoided. 8.6.2 The measurement, monitoring, and reporting requirements, particularly those for compressors, enable the AER to effectively enforce compressor seal venting requirements under a fleet average approach. Compressor seal venting is well defined and practical to quantify. Managing compressor seals as a fleet will allow operators to best allocate capital and effort. Unit-specific vent-rate limits were deemed too restrictive and did not account for the different variables in managing compressor-seal maintenance. A commenter asked the AER to provide the duration of the compressor seal test. 8.6.2 The AER considered adding a time requirement but given the wide range of flows and various measurement devices a minimum time was not practical and could cause confusion. The AER deems the measurement sufficiently accurate if the uncertainty and back pressure requirements are met regardless of the amount of time used for the test. One reader asked the AER to indicate what flow meters would be fit-for-purpose for compressor seal vent tests as compressor seals typically vent at very low flow rates and are subject to backpressure issues. One commenter asked the AER to consider a "step down" program, for duty holders who are able to demonstrate that they have an effective program in place to detect compressor-seal leaks, that would move the annual testing requirement to once every two years. An example of an effective program could be monitoring the compressor temperature on a daily basis. Temperatures above normal would result in a packing change-out. 8.6.2 The AER updated the measurement device criteria in section 8.6.2.1. to address backpressure issues and low vent rates. 8.6.2 The AER is not considering a performance-based compressor-seal testing frequency program at this time. Annual testing can be aligned with regular service intervals, fugitive emissions surveys, or ongoing monitoring/ preventative maintenance. Compressor seal emissions vary by make, model, process conditions, and service. Due to the variance introduced by these factors, seal testing is the most appropriate way to estimate emissions from compressors. Section 8.6.2.1(2) updated to specify test parameters. Commenters asked why the AER is requiring that all testing points be accessible and clearly identified prior to January 1, 2020? 8.6.2 Testing points need to be clearly identified and accessible on January 1, 2020 to provide consistent measurements and allow for safe and accessible measurements. This timing aligns with the compressor-testing requirements. Page 15