OGAA

A: 1) The roads can be included under the ancillary application. 2) Only the borrow pits being applied for need to added to the table. However the additional pit not being applied for will be considered as part of the cumulative area.

A: If the replacement is in-kind, it is deemed an NOI (which would require the submission of a Notice of Construction Start, Notice of Pressure Test and Leave to Open for that activity). There is no notification or consultation required for an NOI because those are within the scope of the permissions and authorities on the application approvals. If the pipe changes at all, it is considered an amendment; consultation or notification would be required based on the class of the amendment (major or minor).

A: Sumps located on privateland must be submitted with a well permit application.

A: There is now an email address to which stakeholder information may be submitted: OGC.WrittenSubmissions@bcogc.ca. It is only to be used for submissions from affected persons or landowners as per OGAA section 22(5). The format of the submission should be the same as referenced in the manual (i.e. they may use the submission form or any other form of documentation such as a letter which provides the information the Commission needs to consider their interests).

A: An Agricultural Lease holder is a landowner. One who has a lease has an ownership: a disposition of Crown land issued under the Land Act. Woodlot licensees are rights holders under the Consultation and Notification Regulation, so some notifications and consultations apply to them, but they are not landowners and Section 31 of OGAA (requirement to notify landowners upon amendment) would not apply.

A: No. Applicants are required to list each tenure regardless of holder, as the line list must demonstrate that each rights holder (tenure specific) was addressed as per regulatory requirements.

A: The intent of the mapping requirements is to help parties visualize how the potential oil and gas activity affects them. The scale of the maps is at the discretion of the applicant.

A: Any additional assets held by the company do not have to be included within the line list.

A: Any authorized signatory of the applicant company may sign the Written Report Cover Sheet, accepting responsibility for the information contained in this form.

A: Yes, if the campsite requires a Licence of Occupation, please apply for both temporary and permanent on the application.

A: A frac-sand storage sites is a Crown Land Application, under Miscellaneous Forms and Guidelines. Frac-sand pits are applied for through ILMB.

A: The current process is outlined in the Corporate Land Management Manual. If a New Permit Holder or Corporate Structure Change Application Form is submitted and is complete, the Commission targets to establish the new permit holder in less than a week.

A: Yes, please submit a Facility Amendment – Add/Delete Equipment for no new land and the Schedule 1 - Well and Facility linkage.

A: This question would be answered, “No” in this instance as the scrubber is not recovering the vented gas stream. The gas would need to be captured and re-compressed into the main process stream through a vapor recovery system, or utilized as fuel gas, etc. to be viewed as recovered.

A: The BC 20 form no longer exists as the required information is now collected in KERMIT. This Change of Service will require a facility permit amendment, and the amendment will be designated major and will require the full consultation and notification.

A: Yes, estimation of small flare / vent sources is acceptable. Refer to Section 11 of the Flaring and Venting Guideline for more information.

A: The current regulatory process for a well linkage change using the new Schedule 1 form (replacement of the previous BC-21 Well or Facility to Facility Linkage) is to submit a well linkage Notice of Intent (NOI) through KERMIT. KERMIT home page ? Applications ? NOI Facility (Upstream) ? Linkage Change This is not a permit application, and prior to the change being accepted, a database check confirmation and population task is completed. The Schedule 1 is then emailed or faxed to the person submitting the NOI. This process is not for new well linkages, as these are part of a facility permit or permit amendment application. Well linkages for in-line testing are part of the in-line testing notice submission process defined in the Pipeline Operations Manual. This process is explained in the revised Facilities Manual.

A: Generally all metering requires a permit.

A: This would require a Facility Permit Amendment – Add/Delete Equipment.

A: For additional equipment, see pages 78/79 of the Facilities Manual for examples of what would require a notice instead of a permit.

A: We require the cumulative facility venting rate, existing and proposed (new).

A: Submit a facility permit amendment to change the maximum H2S concentration at the facility as described. The permit amendment application must include a project description, engineering assessment of the piping and equipment design and materials, and an emissions review which will include dispersion modeling if a continuous flare exists. BC-20 has been replaced by a facility permit application (KERMIT), and the BC-21 has been replaced by the Facility Schedule 1 Form. The landowner and public consultation and notification requirements are explained in the Consultation & Notification Regulation and C&N Manual. For consultation and notification purposes in this case, the application to increase the H2S concentration to 2% H2S would be a major amendment.

A: Air emissions are regulated under the Environmental Management Act. Smaller facilities are authorised to discharge under the Oil and Gas Waste Regulation, which contains NOx emissions limits. Larger facilities including gas processing plants and compressor stations with >3000 kw of compression require a waste discharge permit.

A: Only two sections of the old handbook still exist, Emergency Response Plans and Drilling Waste. All other information is within the application and operations manuals. Emergency Response Plan information is located under "Wells Forms and Guidelines" and Drilling Waste Management is located under "Waste Management and Reclamation".

A: No. The project number is used for applicant internal tracking purposes.

A: These requirements are no longer in effect. The applicant can propose a project up to the established park or protected area boundary. There are no requirements limiting the nature of the type activity up to those boundaries unless otherwise legislated.

A: LLR calculations have been completed for all BC licensees. The calculations will be updated monthly and will be used in review of new well applications and license transfers as they are received.

A: The Commission has begun to request costs from industry members that have completed recent well plugging and reclamation activities in BC. These costs will be used to assist in the preparation of deemed liability costs for the future LLR program.

A: Throughput-based liability costing is an option for addressing the scope and scale of facility liability. The future facility liability costing method would be rolled out to industry during engagement for the future LLR Directive.

A: Further consultation will be completed with industry. The Commission expects to utilize industry knowledge in preparing deemed liability costs for LLR. It should be noted that liability costs used in the Alberta LLR program will not be used for BC.

A: Under full implementation, it is the intention that the LLR program will result in adequate security to cover well plugging and reclamation activities if a company becomes insolvent. The program is a protection measure to cover liabilities should a company fail to meet its closure obligations. However, there may be a potential for orphan wells should a company become insolvent that has failed to pay the required security.

A: The $150K deposit is not intended to replace the well application fee. Deposits will only be requested from licensees with LLR’s less than 1.0 and will be held by the Commission until the licensee can demonstrate adequate assets exceeding liabilities. The well application fee is not a deposit and is not refunded by the Commission. The one-time, $150K deposit has been included so that the Commission may hold a security deposit for at least one well equivalent from higher risk operators. This has been a common approach for the Commission’s handling former drilling deposits for new operators in BC. While the deposit will be required from all operators with an LLR less than 1.0, it is much less of a barrier to entry than requiring that each operator have an LLR of 1.0 or higher before having a well application approved.

A: The existing production-based Orphan Levy has been enacted in legislation. The Commission has no current plans to seek a change in legislation.

A: The Commission recognizes that other jurisdictions have previously implemented liability rating programs and believes that a consistent process between western provinces is a valid approach. However, there are no existing plans or agreements to harmonize a liability rating program amoung western provinces.

A: LLR ratios for BC operators will be posted to the Commission’s website and will be updated monthly.

A: The Commission will be developing a process for submission of site-specific liability assessments for problem sites first. A process for submission of site specific liability assessments for the remainder of sites is being considered.

A: The reportable spill amounts are found in the Environmental Management Act: Spill Reporting Guidelines. Spills are to be reported promptly; there is no specific requirement under the new regulations to submit a written report within 14 days; however, a post incident report may be requested by the Commission.

A: If the line is crossing lease boundaries by going from one lease to the next, it is a pipeline and must be applied for as a pipeline application.

A: The Pipeline and Liquefied Natural Gas Facility Regulationn, Section 6 (3) (b) states that notice must be given at least 5 days before beginning the work. The C&N effort should have identified the proposed activity and the 5 day period simply gives the recipient adequate notice that the activity for which they were previously consulted / notified, is about to begin. The onus is on the permit holder to assess information shared during C&N and adjust notice accordingly if additional time is required.

A: "Section 76 (1) of OGAA says that carrying out a prescribed activity cannot take place without either the agreement of the pipeline owner or an order from the Commission. Specifically 76 (1) (c) notes that the agreement must be in writing and may be limited to “the construction or the carrying out of an activity....” In the event a party’s efforts to receive written agreement from the pipeline permit holder have failed, the party may apply to the Commission, explaining the situation and requesting an order. The party should provide detailed information with respect to the scope of the project, the perceived impact on the buried pipeline, and the attempts made to secure agreement from the pipeline permit holder. The Commission will then review the information and make a decision on whether or not to issue an order. "

A: The C&N regulation does not apply to roads being proposed within a road allowance. However it is expected that the applicant will be advising any adjacent landowners of their proposed use of the road allowance. Trappers and guides do not require notification as road allowances are simply between quarters.

A: As below, the previously required setbacks are no longer outlined in the Regulation. This is not an error. Operators must still ensure however that environmental objectives set out in the Regulation are met. Furthermore, operators must be aware of other acts that affect their operations. Other acts may include but are not limited to the Water Act, Wildlife Act and the Species at Risk Act. Section 26 of the Environmental Protection Management Regulation (Regulation), Wildlife Habitat Features Identified states: (1) The minister responsible for administering the Wildlife Act, by order, may identify any or all of the following as a wildlife habitat feature: (a) a fisheries sensitive feature; (b) a marine sensitive feature; (c) a significant mineral lick or wallow; (d) a nest of (i) a bald eagle, (ii) an osprey, (iii) a great blue heron, or (iv) a category of species at risk that is limited to birds; (e) any other localized feature that the minister responsible for the Wildlife Act considers to be a wildlife habitat feature. (2) Identification of a wildlife habitat feature under subsection (1) may be by category or type and may be restricted to a specified geographic location. In addition, Section 6.9 of the Environmental Protection and Management Guidebook (Guidebook) Wildlife Construction Setbacks states: The following are the minimum suggested construction setbacks for each identified habitat feature: • Trumpeter Swan Nest – 200 meters; • Other nesting sites (i.e.: Osprey stick nest, sandhill crane ground nests) – 100 meters; • Mineral licks – 100 meters; • Bear dens (applies to winter construction only) – 50 meters; In some cases, additional setbacks may be required due to lack of topographical relief, sparse vegetation density, extensive use of habitat, and other special considerations. Where the minimum suggested construction setbacks are not being maintained, proponents are expected to submit to the Commission, as part of the oil and gas activity application, a rationale for the activity placement in proximity to the habitat feature and demonstrate how the integrity of the feature will be protected through mitigation. The Water Act, Wildlife Act and any other acts and regulations that may affect operations must be adhered to by any operator.

A: Visual quality objectives, as defined under FRPA, do not pertain to oil and gas activity; thus visual quality polygons should not influence application requirements. You are correct in the assumption that visual quality is not regulated under OGAA. In some circumstances where significant values have been identified, or where there is sufficient justification, it may be appropriate to ask an operator to consider or mitigate impacts to visual values.

A: Section 23 of the Environmental Protection and Management Regulation (Regulation) states the riparian classes of wetlands. The wetlands are classed based on size and biogeoclimatic zones. Please refer to the Regulation for more detail on the individual classifications of wetlands, and Section 5 of the Guidebook.

A: As of Oct. 4, no orders regarding environmental values have been established. Division 2 of Part 4 of the Environmental Protection and Management Regulation outlines the process for government to establish orders. Once established, areas under order will be communicated and established spatially in the province's Land Resource Data Warehouse.

A: The Water Act Application Manual has been drafted, but has not yet been implemented; as such it is not available on the Commission website. It is unknown at this time when the Water Act Application Manual will be finalized and posted to the Commission website. In the interim, please refer to the Environmental Protection and Management Guidebook for information regarding seismic lines, stream crossing methods and stream crossing best management practices. Waterbody classification is outlined in the Environmental Protection and Management Regulation.

A: Guidelines for abandonments during drilling operations are found in the Drilling Guideline. Guidelines for cased-well abandonments are found in the Completions Guideline. Cased well abandonments conducted in accordance with ERCB Directive 20 meet the intent of the regulatory requirements for well abandonments in B.C. A cement plug at surface is not required.

A: No, flaring activities are not included in the consultation/notification requirement.  Consultation and Notification is restricted to the applications for activities described in the C&N regulation, which does not include flaring notification. Resident notification requirements prior to flaring are specified in well permits, and is required 24 hours prior to the start of flaring.

A: Yes, estimation of small flare / vent sources is acceptable. Refer to section 11 of the Flaring and Venting Guideline for more information.

A: Yes, a permit application for tower with a scada device would be either a new facility permit or a permit amendment, dependent on if there is already permitted facility equipment on the site.

A: There is no specific requirement for the installation of high pressure or high level shutdown devices in vessels unless specified in a permit condition, or if these devices are used as controls to satisfy requirements of particular sections in the Drilling & Production Regulation such as, but not limited to, Section 39, Safety & Pollution Prevention, Section 45(3), Fire Precautions, Section 50(1), Prevention of Losses. These devices are typically installed as a best practice to ensure measurement integrity and for over pressure protection purposes.

A: The Commission requires the cumulative facility venting rate; existing and proposed (new).

A: If the water is used for frac operations or other methods of oil and gas development and production, a permit is required. A permit is not required for potable water.

A: General guidance on equipment spacing is included on pg 38 of the Well Completion, Maintenance and Abandonment Manual. It is important to note that beyond the guidance provided in the Well Completion, Maintenance and Abandonment Manual it is the responsibility of the permit holder to maintain sufficient equipment spacing under Sec. 45 and 47 of the Drilling and Production Regulation.

A: Section 5 of the Drilling and Production Regulation addresses the positioning of wells.