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Below you'll find a list of Frequently Asked Questions related to our Online Systems and other topics.

Application Management System (AMS) Frequently Asked Questions

What is the Application Management System?

The Regulator’s Application Management System (AMS) is a permit application and information portal that provides a consistent application process for all oil and gas permits.

AMS has shifted the manual, paper based oil and gas permit application process into an online submission process. Historically, the Regulator received approximately 4,000 – 5,000 permit applications per year in either hardcopy or quasi-electronic format (via the KERMIT system). Through AMS, the application content is validated at the time of submission, ensuring application requirements are in the form and manner outlined within the Oil and Gas Activities Act. Through AMS, the number of errors therefore are reduced and a more streamlined process is created.

The Regulator has set up a webpage dedicated to AMS. Additional information on the application process can be found on the Oil and Gas Activity Application Manual webpage.

Does the implementation of the AMS mean KERMIT does not exist anymore?

The Regulator’s KERMIT database still exists. Applications previously submitted via KERMIT will now be submitted via the AMS. Other KERMIT functionality will continue to exist, such as the management of operational pipeline and facility data, as well as compliance and enforcement activities.

What activity types are in scope of AMS?

The following activity types can be submitted through the AMS. More information on completing the application requirements associated with these is found on the Oil and Gas Activity Application Manual webpage.

  • Oil and gas activities: applications for wells, pipelines, facilities, roads, and geophysical exploration
  • Related activities: applications for authorizations through specified enactments under the Land Act and Water Sustainability Act
  • Provincial NEB authorizations: applications for the Provincial authorizations associated with federal pipelines, through specified enactments under the Land Act and Water Sustainability Act
  • Other submission types: Historical data submissions for pipelines and facilities can be submitted via the AMS, as well as ALR assessments on private land.

OGAA versus CER applications. What is the difference?

Applications made to the Regulator via AMS can be either for a permit under the Oil and Gas Activities Act (OGAA) or for authorizations for National Energy Board (NEB) permits. Spatial packages must be prepared separately for these applications.

Do activities have to be submitted individually?

No. An application submitted via AMS can be composed of a single activity or multiple activities. It is at the discretion of the applicant to determine how many activities they want to include in the application.

I submitted the application with no issues, now after my application is set to in-revision, the system requirements have been changed and I have to provide more information/upload spatial data to submit the application again?

This situation can occur when the Regulator makes changes to the system(s) as part of ongoing enhancements. Once an application is set to in-revision, it is treated as a new application when submitted. Any changes made to the system(s) may include new requirements for spatial data, mandatory information etc. which is compulsory to be provided. Enhancements made to the system(s) improve data accuracy and facilitate improved data management and are crucial for the Regulator’s operations.

Why do I need to submit the “FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions” to FrontCounter BC?

This form is required as per INDB 2019-19. The Ministry of Forests, Lands, Natural Resource Operations and Rural Development (FLNRORD) manages s.16 and s.17 Land Act dispositions and will determine if the proposed oil and gas activity will require an amendment to the s.16 or s.17 Land Act disposition or is compatible use.

I am applying for a new well and/or a new facility on permissioned land. Do I need to submit the "FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions”?

Providing the new activity does not include new area, the application form is not required to be submitted to FLNRORD.

Do I need to submit the “FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions” for all applications?

No. The form is needed only for proposed activities with new land area that falls within s.16 or s.17 Land Act dispositions. As per INDB 2019-19, this application form is not required for applications under the Water Sustainability Act or applications that do not require additional land.

Do I need to submit the “FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions” for technical amendments?


How does the “FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions” submitted to FLNRORD impact the timelines on my proposed application submitted to the BC Energy Regulator?

These are two separate processes and will have no impact to applications submitted to the Regulator.

Will the BC Energy Regulator wait until FLNRORD makes a decision on the “FrontCounter BC Application Form for Proposed Activities within Established Section 16 or 17 Land Act Dispositions” prior to making a determination on my application?

No. The BC OGC will proceed with all necessary reviews and determinations. However, prior to commencement of operations, the permit holder must have a decision from FLNRORD.

If an application contains multiple activities and one activity cannot proceed to a decision, is the application as a whole delayed?

Yes, however, an applicant has the option of revising their application in order to remove the activity or can request that the Regulator proceed to a decision. The Regulator may choose to permit some activity and refuse to permit some activity.

I am trying to work on my application, but its status has been set to "Timed Out ". What does this mean and how do I resolve the problem?

When an application has had no activity for three months, the status will change from "In Progress (Draft)" to "Timed-Out". After an additional three months of "Timed-Out" status, the application will be deleted from the system. Once deleted, the application cannot be retrieved. Applicants can change an application's status from "Timed-Out" back to "In Progress (Draft)" by opening the application and saving any of the application pages.

If the application contains multiple activities, can an applicant revise only one activity?

Yes, but the entire application will be put to an ‘In Revision’ status. The applicant can choose to revise portions of, or the entire application.

How do revisions work?

After receiving a request for revision, staff can change the status of an application to “In Revision” to allow the applicant to make the necessary changes. Additional information on the revision process can be found in the Oil and Gas Activity Application Manual webpage.

Can I put an application on pending or withdraw an application through the AMS?

Both the process of putting an application on pending and the application withdrawal process are managed internally. An applicant cannot make these changes through the AMS. Applicants can contact an authorizations manager to make these status changes. Once these status changes are made, they will be shown on the applicants dashboard in AMS.

How do I find out what my AD number is?

You can perform a search within the KERMIT database by activity identifier to determine what a specific AD# is.

Can user access be controlled on a per-application basis?

Securities for applications will work the same as they currently do in Kermit. Once granted the ‘applications’ security role for a company, a user can see all applications started by the company.

Could survey companies be given access directly to the Application Analysis page or do they have to get granted that role on behalf of an applicant company?

Survey companies will need to get access to the Application Analysis role from the applicant company. Once access is gained, users will be able to use the Application Analysis tool without constraints. The Application Analysis role and the Application Analysis tool however, do not allow the user authority to view or edit applications for the applicant company unless the applicant has granted them the Application security role.

If a consultant has access to a specific client in AMS and can view applications of this client in AMS does this mean if 2 or more consultants have the same client they can see each other’s (consultant) applications for the same client?

The Regulator has not made any changes to the way application security roles work with the implementation of AMS. Applicants who give application security roles to consultants and/or representatives are responsible for managing the security of their applications. Representatives will have access to all applications for a specific company once granted application security role.

Can an activity have more than one amendment at a time?

No. An amendment will overwrite current data, which is why applicants cannot apply for more than one amendment at a time. Rules are set up in the system to prevent multiple amendments from being submitted.

What if the applicant wants to amend more than one application type?

Applicants can choose to amend a single activity within a multi-activity application or select the entire permit (approved application).

What activities can I add to my amendment application?

A permit holder can add Associated Oil and Gas Activities and/or Water Act authorizations to an existing OGAA permit. A permit holder cannot add additional OGAA activities to an existing permit.

If I am adding a new pipeline into an existing right of way, is that still a major amendment?

No. The term “major amendment” has been updated and no longer includes the addition of a new pipeline. This definition remains in the Fee, Levy and Security Regulation and the criteria is solely for the purpose of determining amendment fees.

Why are my well authorization numbers being randomly assigned when I upload my shapefile?

Well authorization numbers are assigned in the order in which the features are created in the shapefile. This order, indicated by the FID, can appear to be random when a shapefile is converted from a different format. To ensure these activity identifiers are assigned in the preferred order, we recommend generating the features in ArcGIS when possible.

What will the Data Source attribute on the uploaded spatial data be used for?

The Data Source attributes are being used to infer accuracy and will replace the previously more detailed capture method requirements of ePass.

Can a user modify a field in AMS that was spatially derived from the uploaded spatial data? For example, if a field biologist did a site visit and confirmed that there an application area did not actually intersect with an Old Growth Management Area?

Applicants have the option to change/update some spatially derived workflows in AMS. The user will be required to provide rationale explaining why changes have been made to the spatial data and the updated fields will be denoted in a way that alerts the client and reviewer that a change was made.

My AMS application is showing red exclamation marks in the spatially derived UTM, NTS/DLS and Area fields. I am not able to manually edit them. What should I do to correct this?

There are two ways to correct this:

1. Go to the validate page and validate the application. After validation is complete, you will be see a “Process” button at the bottom of the validation page. Press the button and all the spatially derived values that are showing red exclamation marks will be re-populated.
2. Click validate on the activity page and then click the process button in front of the UTM coordinates.

When do I have to submit the Ministry of Transportation and Infrastructure (MOTI) polygon?

The submission of an MOTI polygon in AMS is mandatory when an applicant requires new cut within the MOTI right-of-way. If the application does not require new cut within an MOTI rights-of-way in the application, it is not mandatory to include the MOTI polygon.

I started my application in AMS but have now been given updated shapefiles for my application, how do I update the spatial data?

In a new application you can upload new shapefiles under the "Spatial Data" tab using the same steps when starting an application. The history of shapefiles uploaded in an application will show on the "Spatial Data" screen under "Spatial Submission Upload History". There is no need to "remove" existing spatial data.

*PLEASE NOTE: Uploading a new spatial data package will overwrite all existing spatial and non-spatial data previously entered into the application.

What if I have permissioned land but no spatial data exists in Regulator spatial data?

In situations where the applicant is submitting spatial data to reference a previously permissioned polygon in a new application or replacing a previously permissioned polygon in an amendment, and there is no existing spatial data in Regulator databases, the land identifier (LAND_ID) attribute must me left empty; this will be the case for all land authorizations approved by the Regulator prior to ePass. In this situation Regulator staff will review to ensure that the polygon is representative of previously authorized land for the applicant.

For more information please see the AMS Spatial Data Submission Standards.

What is my LAND_ID?

Each polygon representing a land area, when authorized by the Regulator, will be assigned a unique Land Identifier (LAND_ID). This number will be referenced throughout the lifecycle of the authorized land polygon. Applicants must reference the land identifier in the submission of spatial data via AMS when referencing a previously permissioned area in a new application or replacing a previously permissioned area during an amendment application.

Applicants can find their unique land identifiers for all currently authorized polygons via data published on the Regulators Geospatial Services page, the AMS Map Viewer OGC Permit Data and/or via the eSubmission portal if the user has been granted permission to access permit information on behalf of an operator. The following features contain land identifiers unique to each polygon:

  • Well and/or Facility Sites AMS
  • Pipeline Rights-of-Ways
  • Road Rights-of-Ways
  • Associated Oil and Gas Activities and Ancillary Activities

When I click on the map button within an application in AMS the map of the province comes up but I cannot zoom to the shape or see any layers

Please ensure you add * to your pop-up blocker exceptions in your web browser settings to enable use of the map. You may need to contact your IT department for assistance with this browser configuration issue.

What happened to the ePASS system?

The ePASS system retired as of July 11, 2016. Spatial data now comes in via AMS or via eSubmission.

What if the applicant hasn’t chosen all the contractors at the time of application?

Within the application, ‘contractors’ are a list of the ‘experts’ that were used to supply information for the application as well as enable ‘a notice of use of professional designation’. This notice is simply an e-mail to the contractors advising them that their professional designation has been used on an application submitted to the Regulator; as well as providing notice of the change in a status of the application. Contractors can include Land Agents, Engineers and Archaeologists. Contractor information within an application assists staff during reviews by providing correct contact information.

Providing contractor information within an application has no effect on who can access the application, nor does it have any bearing on who can work on a permitted activity in the field.

My Master Licence to Cut (MLTC) is showing with (expiring) – Why?

As per Forest Act s.47.5 (2)(a), a Master Licence to Cut (MLTC) cannot exceed a term of 10 years. To ensure cutting permits associated to the Master Licence to Cut are valid for the term of an OGAA Permit, the Regulator will replace Master Licenses to Cut twenty-three months prior to the expiry of the current MLTC. The Regulator has enhanced AMS to display those MLTC’s that will be expiring with a status of (expiring).

I have an open cutting permit that was issued under an (expiring) MLTC. What is happening to that cutting permit?

Cutting permits issued under an expiring MLTC are still valid and permit holders can continue to cut under those cutting permits for the areas of cut permitted until the MLTC expires. However, because the MLTC is expiring, open cutting permits cannot be modified.

Can I modify a cutting permit that was issued under an expiring MLTC?

No, cutting permits issued under an expiring MLTC cannot be modified.

Can I add a new cutting permit under an expiring MLTC?

No, new cutting permits cannot be added to an expiring MLTC.

If I can’t modify a cutting permit or add a new cutting permit under an expiring MLTC, what do I do?

You must first ensure you have a new MLTC; then, within your amendment application you can apply to add a new cutting permit to your activity for the additional area of new cut.

How do I get a new MLTC?

The Permit Operations & Administration Branch will automatically replace and send permit holders a new MLTC 24 months in advance of the current MLTC expiry date; these will need to be signed and returned before they are valid. If an applicant does not have a current MLTC, they will need apply for one; please see the Permit Operations and Administration Manual for the form and direction. For any questions or concerns relating to the MLTC, please submit a service desk request to Permit Operations & Administration.

How do I add new cut when an MLTC is expiring?

To add new cut for applications that are in progress or in revision, click the plus button shown on the right hand side of the forestry table. Select the applicable Forest District from the drop down list. A valid MLTC will populate into the table and the “Area of Proposed Cut Over Crown Land and MoTI (ha)” field will be editable. Upon a positive decision, the Regulator will issue a new cutting permit under the new MLTC.

I’ve tried to edit the forestry table, but a new MLTC does not display. What do I do?

The Master License to Cut will not display if the applicant does not hold a valid MLTC. The applicant must apply for a new MLTC; please see the Permit Operations and Administration Manual for the form and direction. For any questions or concerns relating to the MLTC, please submit a service desk request to Permit Operations & Administration.

When I submitted my application, the MLTC was not expiring. While my application was in review, the status of the MLTC changed to “(expiring)”. Do I have to revise my application?

No, if the MLTC expires while an application is in review, a new cutting permit will be issued under the new MLTC upon approval.

How do I report cut on an application that has been issued two cutting permits?

Cut is entered with the submission of the Post Construction in eSubmission, all valid MLTC’s and cutting permits will be displayed in eSubmisssion.

Will this system allow multiple forest districts to be entered within one application?


What does Resource Management Zone (RMZ) mean in the context of the stewardship screen?

Based upon the location of the activities included in the application, the applicant must follow the Land and Resource Management Plans (LRMP’s) as per the Environmental Protection and Management Guideline, specifically the special management zones. Since some LRMP’s do not define “special”, the Regulator has included all RMZ’s. The applicant will be required to review the applicable LRMP to determine if further rationale is required, including Mitigation Plans, where applicable.

Will proponents be able to apply for a project prior to the 45 days expiring if mailing is the only option?

Applications can be submitted once obligations under RCNR have ended. Applicants wishing to submit an application prior to the response period timeline obligation ending, may include letters of non-objection with their application or apply to the Regulator for an exemption to these timelines.

What if the applicant has an exemption from the 30 day consultation period?

Applicants can select ‘yes’ to the exemption and must upload the approved exemption.

For Consultation and Notification (C&N), what will the system do if someone gives a verbal non-objection but isn’t willing to sign a letter?

As with current processes, the Regulator does not accept a verbal non-objection. If a documented non-objection cannot be obtained, the applicant cannot apply prior to the specified timeline. The line list would require ‘yes’ to be selected under ‘non-objection letter’ for all listed landowners and a non-objection letter must be submitted with the application for each landowner.

Are applicants required to notify/consult water wells (drinking water) within the C&N distances on all applications?

Any application subject to consultation and notification requirements under the RCNR will require notification. As per s. 11(2) (b), if all or part of a known community watershed is established or continued under OGAA, notification is required to each person who holds a construction or operating permit issued under the Drinking Water Protection Act within the notification distance.

Are we required to notify/consult with water licence holders within the C&N distances on all applications or just water applications?

Any application that requires consultation and/or notification under the RCNR requires consultation or notification (as applicable) with water licence holders. The RCNR includes licences under the Water Sustainability Act within the definition of “rights holder”.

Are we required to notify/consult with geophysical programs (seismic lines) within our C&N distances?

Yes, OGAA permit holders are “rights holders” under the RCNR.

If we can determine that a geophysical program is complete would we still need to include the geophysical program in our C&N?


What is considered a related structure for a school?

There is no definition in the RCNR although the Commisison would consider structures connected to a school such as outbuildings as well as structures where a number of people congregate to be a “related structure”. Please contact the Regulator if you have any quesitons about whether a structure is a “related structure” for the purposes of section 8(2).

Is there guidance for sending letters to Trappers? It is getting harder to determine Trapper’s contact information as Government data only shows the Trapper Tenure #. In some cases, the address of the FNLRORD district office is provided, but FLNRORD does not want the letters sent to them.

Applicants are encouraged to contact FLNRORD for trapper or guide contact information. An applicant can request an exemption provided they demonstrate the efforts they have made to obtain the trapper(s) or guide(s) contact information prior to application.

If the permit grants a certain number of storage tanks, or other equipment, but the permit holder has not yet installed all tanks or equipment on site, is RCNR required to install tanks that have already been permitted?


Is the C&N template going to change?

A new RCNR Line list has been created to reflect the new regulations and can be found under Supporting Documents in Chapter 6 of the Oil and Gas Activity Application manual. Further guidance will be provided for application requirements specific to line lists.

Why are there errors in my line list?

There can be various validation errors with the line list:

The header of both line lists provide instruction on the formatting. Applicants CANNOT MANIPULATE the line lists to change the formatting - this will give an error. In both the Rights Holder Engagement and the Consultation and Notification line lists, any values that can be selected from a drop down list SHOULD be selected from that list. If there is any difference between the typed value and that provided in the drop down list, the system will generate an error. Selecting values only from the drop down list will avoid this issue.

Applicants will also get errors if they:

  • Cut and paste content from one document to the line lists. This will overwrite the formulas within the spreadsheet and give errors.
  • Clear the data and formulas in the list. If the formulas are removed it will give an error.
  • Enter incorrect formatted values. The system identifies where to separate these values via punctuation, etc, and if there is extra punctuation, there will be an error.
  • Try and upload a Rights Holder Engagement line list instead of the RCNR line list, or vice-versa.

If the letter is sent out prior to May 31st but the response period won’t end before May 31st, does the 30 day response period need to be noted on the letter?


If a notice or invitation to consult letter referenced the old response period but we gave it the full 30 days before we applied? Would our letter be deemed adequate?

The letter would be deemed adequate only if the service period and response period timelines ended prior to June 1. If the response period will not end before June 1, the letter must include the timelines and letter content requirements outlined in RCNR.

We consulted with landowners for multiple projects at the same time to avoid nuisance notices. The service period and response periods, under the previous regulations, ended prior to June 01st but we will be submitting applications over a period of time after June 01st. Is that sufficient for RCNR?

Applications that are submitted after June 01st are required to follow letter content and timelines outlined in RCNR.

With regard to the content of an invitation to consult, how specific is the Regulator expecting estimate of dates to be? Can the letters contain Q1 and Q2?

As per section 20(2) of the RCNR, the invitation to consult must include an estimate of the dates that phases of an activity will begin and end. Providing a month or a quarter (i.e. Q1, Q2, Q3 or Q4) as estimated dates is acceptable.

If a notice or invitation to consult, contained estimated dates that the activity will begin and end; but those dates change, are companies required to re-notify?

The Regulator encourages companies to use best practices and re-notify.

If notice is hand delivered, but no-one is home, is leaving it at their door considered delivered?

Yes, as per s. 2(1)(e ) of the Service Regulation, this would be a method of service “by attaching a copy to a door or other conspicuous place at the address at which that person resides or carries on business”. Section 2(2)(d) states that the document would be deemed to be received “if given or served by attaching a copy to a door or other conspicuous place, on the third day after it is attached.”

In the case of Canada Post, if notice is sent via registered mail and there is confirmed delivery notification, can we waive any remaining days? Alternatively, if we have a read receipt/delivery receipt when sending via email can we then deem it received once the read receipt/delivery receipt is received?

As per the Service Regulation, a document is deemed received when the service period has ended. There is no provision to consider the notice deemed received on an earlier date.

Is there a minimum increase to area that will trigger a decision maker to determine additional C&N is required for an amendment?

Decision makers will consider the amendment and how the amendment may, or may not, impact landowners and/or rights holders to determine if additional consultation and/or notification is required. Applicants are encouraged to contact the Regulator to discuss their amendment prior to submission, if they have questions or concerns about consultation and notification that may be required for their specific project.

If there was a written submission submitted on a project and an amendment to the project is now required, are the written submissions considered to be a previous unresolved concern?

Decision makers will consider the amendment and how the amendment may, or may not, impact previous written submissions and/or concerns. If applicants have concerns about an amendment and how it may be impacted by previous written submissions, they are encouraged to contact the Regulator to discuss their amendment prior to submission.

Will there be a way to capture the previous C&N for an amendment?

Previous, or historic C&N will not satisfy current C&N requirements that are applicable to an amendment, however it can be produced for consideration. The Regulator will assess the amendment application and determine whether additional C&N will be required as per section 31(5) of OGAA.

Is notice or an invitation to consult at the Regulator’s discretion true for both revisions and amendment applications? If so, is the consideration criteria the same for both?

Consultation and/or notification for revisions is not at the discretion of the Regulator. The requirements for revisions and are set out in s. 13 and s.14 of the RCNR.

The Regulator’s decision maker does have discretion on whether or not to require consultation and notification on an amendment application and to whom that consultation or notification must be sent to. However, the decision maker does not have discretion over the content; which must be in accordance with the RCNR.

For an application revision to include a sour pipeline, who should be notified?

Section 14 of the RCNR states which parties are required to be notified for revisions.

Can you put all of your proposed activities on one construction plan or do they have to be separated?

Yes, the preference would be to include all activities on one construction plan.

What is the maximum file size of an attachment that I can upload into an AMS application?

The maximum file size is 50 mb.

How are wells classified in AMS?

The well classification will default to ‘Developmental’ and the applicant can change it, if necessary.

Why doesn’t the oil and gas field name auto populate?

The oil and gas field name is pulled spatially and may not populate because the well point is located outside of a field or located where two fields overlap. Wells must be named based on the well naming convention.

Are PNG title numbers entered for each WA or once for the wellpad?

PNG title numbers are entered for the wellpad. If the application involves multiple wells on the same pad with different PNG title numbers; the applicant can submit all applicable PNG title numbers for the entire wellpad.

What if there are multiple PNG title numbers? How does the user add more title numbers?

The user selects the ‘+’ button to add the additional PNG title numbers.

Can applicants apply for multiple wells and apply different variances/exemptions to each well?

Yes, exemption requests are specific to each particular well.

What if a well is applied for and permitted as Developmental, but then the applicant determines it should be a different classification?

The same process exists as it does now. The applicant will be required to submit an amendment to change the classification.

How do I select ‘et al’ for working interest partners (in addition to working interest partners selected from the “Working Interest Partner” dropdown, or if they are not available from the dropdown list)?

If the proponent wishes to submit either an ‘et al’ along with names working interest partners, or only add a ‘et al’ with no named working interests, they should simple select the “More Than One WIP” checkbox.

Once they save the well overview page, they will see the ‘et al’ shown in the well name on the Well Details.

What is the difference between Associated Oil and Gas Activity and Ancillary Activity?

Associated Oil and Gas Activities are related to OGAA activities and are required to support and carry out the OGAA activity. Ancillary Activities are related to NEB activities and are required to support and carryout the NEB activity.

Are stand-alone Crown land applications submitted through AMS?

Yes, but some terminology has been clarified. Activities previously referred to as stand-alone Crown land applications or ancillaries will now be referred to as the following:

  • For OGAA related applications: ancillaries will now be referred to as an “Associated Oil and Gas Activity” and can be applied for as a single activity application or as part of a multi-activity application.
  • For NEB related applications: ancillaries will continue to be referred to as “Ancillaries” and can be applied for as a single activity application or as part of a multi-activity.

If my road or pipeline application has stream crossings, do I have to apply for them separately?

You can apply for these activities together in the AMS. Make sure to select both ‘road’ (or pipeline) and ‘changes in and about a stream’ when you select the activities for the application.

I am applying for a new proposed pipeline application. The proposed application partially overlaps an existing permissioned area for the same company. Do I need to include the land area that is already authorized under another permit in my spatial file?

There are different scenarios to be considered when preparing a pipeline application that includes application area that overlaps existing permissioned area. Some direction has been provided below for a few of the more common scenarios:

  1. If the proposed pipeline application overlaps a permitted pipeline right of way, regardless of ownership; the polygon for the proposed pipeline application area should overlap the permitted pipeline right of way area. Show the proposed pipeline application area as if the permitted pipeline did not exist.

    The segment (line data) can extend beyond the proposed application area to the tie-in point.The line data should reflect the physical length of the pipe.
    • Blue: Proposed pipeline application area
    • Blue Thatched: Proposed pipeline application area overlapping a permitted pipeline right-of-way
    • Black Line: Proposed pipeline segment
    • Green: Permitted pipeline right-of-way
    • Red Line: Permitted pipeline segment
  2. If the proposed pipeline application will be tied into a permissioned well/facility area and the ownership of the well/facility and the proposed pipeline are the same, the proposed pipeline segment (line data) will extend beyond the pipeline application area to the tie-in point. The line data must reflect the actual physical length of the pipe.

    The polygon for the proposed pipeline application area will reflect the area required to adjoin the well/facility area, it does not need to include the area overlapping the existing permissioned well/facility area.
    • Blue: Proposed pipeline application area
    • Black Line: Proposed pipeline segment
    • Green: Permissioned well/facility
  3. If the proposed pipeline application will be tied into a permissioned well/facility area and the ownership of the well/facility and the proposed pipeline are NOT the same, the proposed pipeline segment (line data) will extend beyond the proposed pipeline application area to the tie-in point. The line data must reflect the actual physical length of the pipe.

    The pipeline application area will overlap the existing permissioned well/facility to include the area required for the new application.Some exceptions may apply when applications are on private land.
    1. Blue: Proposed pipeline application area
    2. Blue Thatched: Proposed pipeline application area overlapping permissioned well/facility area
    3. Black Line: Proposed pipeline segment
    4. Green: Permissioned well/facility area

If you have a unique scenario that does not fit into these examples, please contact an Authorizations Manager or submit a service desk request to:

I am applying for piping from a tie-in point on one permissioned wellsite area to a tie-in point on another permissioned wellsite area that are adjoining. Is this a new pipeline application, an amendment or facility piping?

Note: Once a pipe leaves the wellsite boundary, even if running to an adjacent wellsite; the application must be submitted as a pipeline; either as a new pipeline application or an amendment pipeline application.

If a pipeline segment is being proposed from a tie-in point on one permissioned well/facility area to a tie-in point on another permissioned well/facility area, where the well/facility areas are adjoining, there are options for the proposed application:

  1. If the applicant for the proposed pipeline segment is not the same as the permit holder for the well/facility areas, the proposed pipeline must be submitted as a new application. The application must include both the segment (line data) and the pipeline application area shown as overlapping the permissioned well/facility areas.
    • Blue Thatched: Proposed pipeline application area overlapping permissioned well/facility areas.
    • Black Line: Proposed pipeline segment
    • Green: Permissioned well/facility areas.
  2. If the applicant for the proposed pipeline segment is the same as the permit holder for the well/facility areas, the application may be submitted as a new application or an amendment.
    1. As a new application:
      The proposed new pipeline application must include both the segment (line data) and the pipeline application area shown as overlapping the permissioned well/facility areas.This option will result in a new project number.
      • Blue Thatched: Proposed pipeline application area overlapping permissioned well/facility areas.
      • Black Line: Proposed pipeline segment
      • Green: Permissioned well/facility areas.
    2. As an amendment:
      This scenario is only applicable if the applicant for the proposed amendment pipeline application and the permit holder for the wellsite are the same. The proposed segment, from tie-in point to tie-in point, can be added to an existing pipeline project by submitting an amendment application as a technical only amendment.
      • Green: Permissioned pipeline right of way adjacent to permissioned we//facility areas
      • Black Line: Permissioned pipeline segment
      • Red Line: Proposed pipeline segment

If you have an application that does not fit into these scenarios, please contact the Authorizations Manager for the zone in which your application falls or submit a service desk request to:

I need to add a new segment into an existing right of way where no new area is required. How do I apply?

A technical only amendment is applicable when a permit holder is amending an existing pipeline project to add a new segment and the new segment falls entirely within the permissioned area of the existing pipeline project’s right of way. The proposed pipeline segment (line data) must reflect the physical length of the new pipeline segment. For further information on how to submit this application, please see the example in the AMS System User Manual - Adding a new pipeline segment

  • Green: Permissioned pipeline right of way
  • Black Line: Proposed pipeline segment
  • Red Line: Permissioned pipeline segment

If you have an application that does not fit into this scenario, please contact the Authorizations Manager for the zone in which your application falls or submit a service desk request to:

I need to add a new segment into an existing right of way but also need additional land. How do I apply?

The permit holder must submit a land and technical amendment if the additional land area is needed. The amendment application must include both the updated segment (line data) and the proposed additional pipeline application area for the additional land area.

  • Green: Permissioned pipeline right of way
  • Black Line: Permissioned pipeline segment
  • Red Line: Proposed pipeline segment
  • Blue: Proposed pipeline application area for the new land area

If you have an application that does not fit into this scenario, please contact the Authorizations Manager for the zone in which your application falls or submit a service desk request to:

Do you have to submit pipeline segments in order to start an application?

Yes. Pipeline segments are part of the spatial data that is uploaded into the application.

Are pipeline installations mandatory?

Pipeline installations are mandatory only if present on the pipeline.

Can pipeline installations be added later in the application process or do they have to be uploaded with the spatial data package up front?

Applicants can upload additional pipeline installations at any point during the application preparation within AMS as long as the spatial for the correct corresponding segment IDs has been submitted. Users may wish to become familiar with the spatial submission standards outlined in the Spatial Data Submission Stanards manual.

I am trying to submit an application adding new segments and new pipeline installations to my project, but I cannot add the installations via new spatial or the “Add Installation” button?

If you are adding both new segments to your project and new installations to those new segments, you must ensure that you have submitted the spatial for the new segments before you try to add the associated pipeline installations to them. All installation points must correspond to the correct (and available) Segment IDs for the amendment or uploading pipeline installations will not work.

Is there any limit on the number of pipeline installations that can be included in a single application?


Can a pipeline be split into arbitrary segments for consultation or scheduling reasons?

Yes. It is at the discretion of the applicant.

Is there a limit to the number of pipeline segments?

No, the past requirement of only five segments per pipeline application has been removed. AMS supports any number of pipeline segments.

What is the definition of pipeline segment?

A segment is defined as a section of pipeline within the pipeline system. A pipeline system is made up of one or more segments of pipeline or a group of pipelines; including gathering lines.

Does the pipeline rights-of-way need to be segmented to match engineering segments?

Spatially, we have separated the surface pipeline rights-of-way from the pipeline centerline requirements. Pipeline rights-of-way will be a polygon shape file; while the pipeline centerline is a line. Pipeline centerlines will be shown from tie-in point to tie-in point and must be located within the surface rights-of-way or a wellsite/facility polygon. The surface right-of-way is required to determine impact to the land and is required on both private land Crown land. Construction plans should show the right-of-way segmented to match engineering segments for ease of future amendments or transfers.

What is the difference between "Road Segment Right of Way Width" and "Maximum Right of Way Width" in a road application?

Road Segment Right of Way Width:

Is the right of way width for each road segment that includes the running surface and area needed to support the construction and maintenance of the road segment.

Maximum Right of Way Width:

Is the maximum right of way width that includes all areas needed to support the construction and maintenance of the road as defined in the Oil and Gas Road Regulation.

Do roads have to be submitted with a well or a pipeline or can they be tracked with their own identifier and not linked to either of those activities?

Roads can be submitted as part of a multi-activity application or as a single activity application, but they do not have to be applied for specifically with the well or the pipeline. Roads will get a unique activity identifier and are not tied directly to the well or pipeline.

Notification for Pipeline Activity

Why is the BC Energy Regulator (BCER) making this change?

This is being implemented to provide Permit holders a means of notifying the Regulator of administrative and/or pipeline activity where an amendment is not necessary.

Does this apply to both OGAA regulated and CER regulated pipelines?

This only applies to OGAA regulated pipelines.

What types of pipeline activities can be submitted as a notification?

Only those activities listed in the notification permission can be submitted as a notification. These include:

  • Changes to outside diameter
  • Adjusting the wall thickness
  • Changes to the pipe grade
  • Certain pipeline product changes as identified in the Allowable Pipeline Product Change Table
  • Reducing H2S
  • Reducing the maximum operating pressure
  • Changing the flow direction
  • Minor modifications to an installation
  • Splitting a pipe segment

Notifications can be submitted only after the notification permission has been added to the pipeline permit.

Can notifications under this technical permission be submitted for any pipeline activity?

No. Permit holders can only submit a notification for those pipeline activities listed within the notification permission. Notifications can be submitted only after the notification permission has been added to the pipeline permit.

How do I get the notification permission added to my permit?

Effective July 10, 2023, the notification permission clause will be added to all new pipeline permits. It will also be added to all pipeline amendments and when new permits are issued because of a segment split due to a transfer or reconciliation. Permit holders must ensure the notification permission has been added to each permit prior submitting a notification.

What do I do if the pipeline changes meet the criteria for notification, but my permit does not include the notification permission?

If the pipeline permit does not include the notification permission, permit holders must submit an amendment application for all changes including changes that meet the criteria for notification. After the amendment application has moved to a positive decision, the notification permission will be added to the permit. Once the permission has been added, the permit holder may use the notification process for future pipeline changes that meet the criteria for notification.

What do I do if the pipeline change does not fit the criteria of notification?

Permit holders must submit an amendment application for any changes that are not identified in the notification permission or where the notification permission has not yet been added to the permit.

I need to submit an amendment for activity that doesn’t fit the notification criteria. Can I include the notification activity with my amendment?


If I am required to submit an amendment application for changes that meet the notification criteria because the notification permission has not been added to my permit, what will the timelines be for that amendment application?

If the BCER determines that a pipeline amendment application meets the criteria for notification, the review process will be streamlined for a timely decision. Upon receipt of the amendment application, BCER will determine if First Nations consultation and/or landowner consultation is required. Applicants who are concerned about application timelines may request the amendment application be prioritized or contact the appropriate Authorizations Director at the Regulator to discuss timelines.

I need to make several changes to the pipeline. Can I submit an amendment and a separate notification at the same time?

No. Permit holders have the option of including all the required notification changes within the amendment application or waiting until a decision is made on the amendment; before proceeding with the notification utilizing the Historical Submission or e-Submission processes, or vice-versa.

Note: Permit holders must ensure that all amendments and/or historical submissions have been approved and/or accepted before submitting a notice of pipeline change in e-Submission, or vice-versa to prevent data from being overwritten.

Now that my permit has had the notification permission added, how can I submit notifications to the BC Energy Regulator?

Notification for pipeline changes are submitted two ways:

  • For notifications regarding pipeline segment splits and minor modifications to installations; permit holders will upload new spatial data utilizing the Historical Submission in the Application Management System (AMS).
    • Note: spatial data requirements for segment splits using this process are different than the spatial data requirements for an amendment. Permit holders are encouraged to read the AMS User Manual for specific guidance regarding the different spatial data requirements. Further guidance about allowed notification changes can be found in the Oil and Gas Activity Operations Manual
  • For notifications on the remaining pipeline activities listed in the notification permission, permit holders will submit the Notice of Pipeline Change through e-Submission.

Permit holders must ensure the notification permission has been added to each permit prior to submitting a notification.

Is this notification submission the same as a Notice of Intent (NOI)?

No. Permit holders can submit a notification only for those activities identified within the notification permission. There is no change to the current NOI submission.

Reduce Maximum Operating Pressure (MOP) is already an NOI. Do you now need to submit this as a notification?

Permit holders can continue to utilize an NOI to submit changes to the MOP. However, where permit holders are submitting a notice of pipeline change, the option to reduce MOP is available.

Can I proceed with the pipeline activity work once I submit the notification?

Permits holders are required to submit the notification a minimum of seven days prior to commencing work. Work may commence after the seven-day period has passed or after the permit holder has received confirmation from the BCER that the notification has been accepted, whichever occurs first.

Do I have to wait for the BCER to accept the notification through the Historical Submission or the notice of pipeline change through e-Submission before proceeding with the pipeline activity?

Permit holders may begin the pipeline activity either after the seven-day period has passed or upon confirmation that the BCER has accepted the notification, whichever occurs first.

I need to reconcile my pipeline. Do I need to submit this separate from the notification?

Permit holders will submit a Historical Submission for a pipeline reconciliation and can include the pipeline notification changes as part of the historical submission at the same time.

Note Permit holders must ensure that all amendments and/or historical submissions have been approved and/or accepted before submitting a notice of pipeline change in e-Submission, or vice-versa to prevent data from being overwritten.

Can I submit a notification for any pipeline product change?

No. Notifications for product changes are limited to those products identified within the Allowable Pipeline Product Change Table in Chapter 11 of the Oil and Gas Activity Operations Manual.

Can I submit a notification for changes to H2S?

A decrease to H2S may be submitted as a notification; however, increases to H2S must be submitted as an amendment.

Will the notification require spatial data?

If the notification includes minor modifications to an installation and/or a pipeline segment split, spatial data will be required. Permit holders must follow the spatial data guidance outlined in the AMS User Manual for notifications.

Note: Spatial data requirements for segment splits using this process are different from the spatial data requirements for an amendment. It is important that the correct guidance is followed.

What is a minor modification to an installation?

A minor modification to an installation may include administrative updates to the installation numbering because of a segment split. Other minor modifications include minor pipeline activity changes but does not include updates to UTM locations or relocating installations where consultation is required.

I need to split a segment on a deactivated pipeline. Can I submit the segment split as a notification?

If the permission has not yet been added to the permit, the permit holder must submit an amendment to record the segment split and get the notification permission added to the permit. After the notification permission has been added to the permit, future segment splits can be submitted as a notification.

Can I submit an amendment for the segment split if I don’t have the notification permission in my permit yet?

Yes. The segment split will be approved with the amendment application. The notification permission will also be added to the permit. After the notification permission has been added to the permit, future segment splits can be submitted as a notification.

Area-based Analysis Frequently Asked Questions

What is Area-based Analysis?

Area-based Analysis (ABA) is a framework for managing the impact of oil and gas development in northeast BC. ABA monitors cumulative impacts to environmental values to allow for improved consideration of landscape level effects in decision making.

What areas are subject to Area-based Analysis?

ABA applies across the Peace Region of northeast BC.

How does Area-based Analysis work?

ABA measures incremental disturbance to environmental values across ecological assessment areas in northeast BC. When disturbance exceeds an identified trigger, the risk status escalates from normal, to enhanced management and regulatory policy. Activity in high-risk ABA status areas requires increased management actions.

What values are included in Area-based Analysis?

There are four values in ABA at this time:

  • Hydro-riparian ecosystems
  • Old forest
  • Wildlife
  • Old Growth Management Areas

Who will have access to the ABA information and data?

ABA status information and maps can be accessed through the ABA website at and spatial data can be accessed through the associated FTP site.

How does ABA fit with current regulations?

Area-based analysis integrates strategic direction from the Environmental Protection Management Regulation into a coherent framework. This framework considers the material adverse effect proposed and existing development on environmental values identified under Governments Environmental Objectives.

What is the scope of Area-based Analysis?

Area-based Analysis follows the outline identified in the 1999 document “Cumulative Effects Assessment Practitioners Guide” prepared for the Canadian Environmental Assessment Agency.

Scoping consists of five basic steps:

  1. Identify the issues of concern
  2. Select the appropriate values
  3. Identify the spatial and temporal boundaries
  4. Identify the actions that impact the values
  5. Identify potential impacts from the actions and possible effects.

What are the potential benefits?

One of the best methods to manage resource development and environmental/cultural conflict is to share the information available with all interested parties. Identifying the values important to each First Nation ensures that these values are recognized and considered early in the application process.

How can First Nations participate in Area-based Analysis?

The Regulator is actively engaged in the Regional Strategic Environmental Initiative (RSEA) to listen to First Nation concerns regarding cumulative effects in northeast BC. The Regulator is also engaging with First Nations and the Aboriginal Liaison Program in field assessments and validation processes (under the FREP program). The Regulator is looking to engage First Nations on an ongoing basis to help guide the continuous improvement of ABA values, protocol and management.

How does Area-based Analysis consider treaty rights?

The Regulator is participating in the Regional Strategic Environmental Initiative (RSEA) to explore approaches to develop a structured assessment of specific treaty rights. Future enhancements to ABA will include the addition of RSEA values and consideration of additional values such as wildlife abundance, clean water and healthy watersheds, biodiversity for hunting and medicinal plants, air and water quality and other treaty rights (peaceful enjoyment).

What are the current ABA results?

ABA Status information is available in the ABA online reports. As of June 2020:

  • ABA Hydro-riparian currently reports 46 water management basins as 46 normal, 22 enhanced management and 2 regulatory policy.
  • ABA Old Forest reports three of six natural disturbance units in northeast BC to exceed the retention targets for Old Forest
  • Old Growth Management Areas are reported as 193 normal and 47 regulatory policy.
  • Wildlife areas are reported as 323 normal, 20 enhanced management and 48 regulatory policy.

What are the strengths and weaknesses of the analysis?

Area-based Analysis (ABA) is a valuable tool for decision makers and resource managers to manage the environment and minimize further impacts. ABA quickly draws attention to areas where the risks of cumulative effects are high to ensure escalated management.

ABA has been developed using structured technology and scripts. This allows ABA to be updated routinely to monitor incremental changes on the land-base. ABA now has five consecutive years of assessments making it the province's most dynamic assessment.

How does the Regulator validate ABA status?

The Regulator is actively reviewing key data and assumptions in conjunction with the Ministry of Forests and Natural Resource Operations and Rural Development (FLNRORD). Specifically the two organizations are working together to:

  • Understand how cumulative effects impact streams, forests, wildlife and biodiversity
  • Understand regional variability and sensitivity to disturbance
  • Model recovery to account for ecological succession and restoration
  • Coordinate a collaborative field program to evaluate the accuracy of GIS based risk assessments relative to field conditions.

Field monitoring ecosystems for cumulative effects

The Regulator has completed extensive field assessments of hydro-riparian areas to verify ABA. Field studies have found a general relationship between field-based stream indicators and landscape level disturbance, however the relationship is complex and confounded by natural disturbances in the northeast. Continued monitoring of streams and new monitoring programs for OGMA and wildlife areas are required.

What are the next steps?

The Regulator is continuously improving ABA, this includes:

  • Validation of existing indictors through science based fieldwork
  • Address stakeholder priorities by delivering new values to ABA
  • Establish new policy to support improved management actions.
  • Reconcile ABA with other provincial initiatives (RSEA/CEF).
  • Explore collaborative stewardship opportunities with First Nations.

Where can industry find ABA information?

ABA information, including maps, reports and spatial data, is available on the Regulator’s website. If you require any additional information please contact

What is the desired outcome of ABA?

ABA endeavors to reduce the cumulative impact of oil and gas activities by minimizing the footprint and environmental impact of operations. Wherever possible the Regulator strives to see no new disturbance where the ABA Status is enhanced management or regulatory policy. When activity is unavoidable in these areas, the Regulator expects industry to reduce their impact by using existing disturbance, minimizing new clearing, limiting ground and vegetation disturbance, applying minimal disturbance techniques and encouraging rapid ecological recovery through restoration.

What if a trigger is exceeded?

Where ABA status is enhanced management or regulatory policy, a Mitigation Strategy is required to document site specific information, demonstrate consideration of the mitigation hierarchy and explain how impacts will be minimized and mitigated. Mitigation Strategies should be developed by a Qualified Professional and align with governments policy for mitigating impacts to environmental value (Environmental Mitigation Policy).

What ABA information is required in the application procedure?

Operators are required to indicate in the Application Management System (AMS) if a proposed activity will impact an ABA enhanced management or regulatory policy areas. If an application intersects an enhanced management or regulatory policy area the applicant must upload a Mitigation Strategy and delineate ABA areas in their Construction Plans.

What can industry do to make sure ABA requirements do not hold up applications?

To deliver effective applications and avoid delays or returns, Industry should include ABA in the planning of all oil or gas activities. Oil and gas activities to be planned in a way that minimizes the development footprint and expedites restoration.

  1. Review ABA Website
  2. Download the ABA Riparian, ABA Old Forest, ABA Wildlife and ABA OGMA shapefiles for use in development planning
  3. Review Supplementary Information for Area-based Analysis
  4. During the development planning process consider:
    • How can I plan the activity to avoid enhanced management and regulatory policy areas
    • Work with a Qualified Professional to draft an ABA Mitigation Strategy
  5. ​What can I do to minimize disturbance?
    • Use existing disturbance, common access and shared corridors
    • Place auxiliary disturbance outside sensitive areas
    • Minimize new land disturbance by narrowing right of ways and reducing clearing
    • Implement strategies that will expedite reclamation

How is Area-based Analysis taken into consideration in the permitting process?

The Regulator considers Area-based Analysis (ABA) in reviewing applications under the Land and Habitat Review. Delegated and statutory decision makers of the Regulator have the authority to request changes to an application to reduce the cumulative impacts, apply permit conditions or refuse an application if the impact is too high.

Treaty 8 Agreements Frequently Asked Questions

Are the Treaty 8 Agreements public?

Yes – they can be found at the following links:

Presentations to provide additional information

  1. BRFN Agreement Technical Workshop BCER
  2. BRFN Agreement Industry Technical Workshop EMLI

When do the new rules required by the BRFN Agreement take effect?

Jan. 18, 2023, the effective date of the agreement.

Can a map and shape files for Area 1, Area A and the remaining area of the Claim Area which are described in the BRFN Agreement be provided?

The agreement referred to landscape- and watershed-level development planning. What is the timeframe for that planning and will industry be provided an opportunity to participate?

Planning will begin in the coming weeks. Some engagement with implicated industry has already begun with more anticipated very soon. The first HV1 plan is targeted for completion in fall 2023. Planning initiatives will concurrently be underway with other Treaty 8 Nations as well. The Treaty 8 Consensus further contemplates Landscape Planning Pilots, which are anticipated to be plans similar in nature to HV1 Plans.

How and when will industry be involved in the land use planning processes committed to within the agreements?

The plans contemplated in the agreements are intended to be Government to Government plans developed with Indigenous nations, to guide both restoration and development. Industry will be engaged, as appropriate, to seek information on relevant development interests, restoration intentions and opportunities, and proposed operational measures that support achievement of plan objectives.

Will a development plan be required for outside the Claim Area and if so, which First Nation will be involved?

Plans contemplated under the agreements are between provincial and Indigenous governments and will be undertaken outside the claim area. Plans will provide direction for resource development in one or more sectors over other areas, but are not anticipated to be required in order for development to proceed.

Now that an agreement has been reached, does this mean the BC Energy Regulator (BCER) will make decisions on new applications more quickly?

The BCER will continue to review and make decisions on applications on private land and on Crown land in the claim areas that do not have new disturbance. For applications that would be affected by the new rules or that are proposed in areas in which disturbance caps will be put in place, more information will be shared with industry soon on a new process for considering and reviewing these applications. This would also apply to applications already submitted to the BCER. The BCER plans to engage industry and individual companies soon to review and discuss each company’s priority application list in consideration of the new rules and the disturbance caps for each area.

Who is my main contact with the BCER to discuss concerns?

If companies have questions or concerns about the status of their applications or how the rules will affect applications already submitted, or yet to be submitted, please contact Sean Curry, VP for Responsible Development and Stewardship.

I have applications awaiting decision that are on the Schedule I list. Now that an agreement has been reached, when can I expect the BCER to make a decision?

The BCER has been consulting with BRFN and other Treaty 8 Nations on applications on the Schedule I or “Existing Priority applications” list, defined in the BRFN Agreement and is moving to decision on application where consultation with relevant nations have been closed and the BCER’s review has been completed. Even if BRFN has agreed to the applications on this list, the BCER will be continuing to consult other relevant Treaty 8 Nations prior to issuing a decision.

The BRFN Agreement notes that existing applications that were previously submitted to the BCER and not on the Schedule I list will be reviewed consistent with the process identified in the agreement. Does this mean these applications will need to be resubmitted and/or start from the beginning of the new referral and consideration process? If so, will there be new application fees?

  • The new rules within the agreement, including caps, would apply to existing applications already submitted and to new applications, where applications are proposed on Crown land with new disturbance. The BCER plans to engage each company individually, once disturbance cap allocations are communicated to companies, to determine what each company’s new priority list of applications will be for 2023 and years ahead, in consideration of each of their caps. It is not anticipated, at this time, that an application previously submitted would need to be resubmitted. No new application fees are proposed for previously-submitted applications.
  • All applications not included in Schedule I must go through consultation with BRFN. A new consultation process has been developed with BRFN that will be communicated to industry shortly.

Is there an opportunity to not re-start an application in AMS pre-Jan. 18 (i.e., restart consultation), where a company has adjusted their application to meet the new rules, such as by minimizing their disturbance from what was previously applied for?

The intent is to allow companies to incorporate new parameters without having to re-start the process and will be considered on a case-by-case basis. Companies considering this should commence pre-engagement with First Nations on the changes anticipated and advise the BCER.

What constitutes disturbance for a proposed seismic exploration program?

"New Disturbance” is defined in s1.1(oo) of the BRFN IA.

How can I learn more about the new consultation process co-developed by BRFN and BCER?

  1. Presentation on New Consultation Process - June 16, 2023
  2. BCER BRFN Implementation Agreement Form
  3. BCER BRFN Guidance Document
  4. Technical Instructions for Map of First Nation Consultation Areas
  5. BRFN Pre-Application Engagement webpage
  6. Email to arrange pre-engagement meetings:
  7. Presentation to Update on New Consultation Process - June 30, 2023

What is the new BCER/BRFN consultation process and how has it been developed?

A new consultation process has been co-developed by BRFN and the BCER to ensure the application referral process meets the requirements of the Blueberry River First Nations Implementation Agreement and respects Treaty rights. This new process also provides guidance to applicants on pre-application engagement with BRFN that must occur before applications are submitted, including important information needed to inform engagement.

As part of the new consultation process with BRFN, the following documents have been developed, for use by applicants:

  1. The BRFN Implementation Agreement Form
  2. Guidance Document
  3. Pre-engagement Record spreadsheet

When are companies expected to start using the new BCER/BRFN Implementation Agreement Form?

Companies are expected to use the new Implementation Agreement Form, effective immediately, for any application within BRFN territory that has not yet been referred to BRFN by the BCER and for any future applications. The Implementation Agreement Form should be completed after pre-application engagement with BRFN is undertaken, but it can be used as a guide for what information should be made available to BRFN, to facilitate pre-application engagement discussions (i.e. group applications where possible, identify how they relate to high value cultural areas subject to ongoing planning, explain how new disturbance has been avoided and consolidated).

For which applications will the new Form and BRFN pre-engagement be required?

  • The new Form and pre-engagement requirements will be required immediately for applications previously submitted but not yet referred to BRFN, as well as all future applications to be submitted. If the application was referred to BRFN prior to the Yahey/ Justice Burke decision, and then consultation halted as a result of the decision, the form will need to be filled out. This applies for applications on both Crown and private land.
  • If the application was previously submitted and is located entirely on an existing site and no new cut is required, the form does not need to be submitted. Additionally, if an amendment was previously submitted and does not include any new development, the form does not need to be submitted. .
  • All future applications types, including applications on private land and technical amendments require the form. For Minor Applications, which are defined in the Form, the expectation for completing the Form will be streamlined.

Will I be required to complete the Form if my application is for an activity located outside of BRFN Claim Area but still within BRFN territory?

  • Yes. The Form is expected to be completed for any application located within BRFN territory.

When and where should the Form be submitted?

  • For new applications and amendments, the Form should be uploaded in AMS under document type “Attachments for Treaty 8 First Nations” and category “Blueberry River First Nations”.
  • For applications and amendments that are already in the system, they can be uploaded as a document type of “other”. An email should be sent to, to notify the BCER that this was uploaded. If an email is not sent, we will be unaware the document has been uploaded and this could cause delays in referring.

Who should I be speaking to at BRFN if I have any questions or if I want to start pre-application engagement discussions?

BRFN has developed a website that will include information for proponents on who to contact within the BRFN Lands Department and how to commence pre-application engagement discussions with BRFN.

How are the new BRFN pre-application engagement requirements different from the general pre-engagement requirements published by the BCER earlier this year?

  • Pre-application engagement is needed to obtain information on proposed development early in the project planning phase, including identifying acceptable locations for oil and gas activities and conditions under which new development can occur. It is encouraged that meetings be scheduled with BRFN Lands Department well before applications are prepared, with a focus on long-term development plans rather than individual applications.
  • All applications now require a Pre-engagement Record spreadsheet to be submitted, outlining the process used to pre-engage with BRFN and discuss any concerns brought forward and how they were addressed. BRFN intends to review this Record before the application is submitted. Specific guidance on how and when applicants should conduct pre-engagement with BRFN, and on what information may be requested, can be found in the Guidance document.
  • Pre-application engagement should focus on short, medium and long-term development plans and identify all associated development. BRFN expects proponents to identify all project and activity components requiring authorization as a whole. Pre-application engagement on an application-by-application basis is not expected (i.e. separate meetings on facility, compressor, well pads and associated infrastructure should not be scheduled – all should be discussed together at the one engagement meeting).

If my application does not meet the rules of the BRFN Implementation Agreement, will the BCER still proceed to refer the application to BRFN for review?

Applications will be reviewed to ensure they meet the requirements of the Implementation Agreement. If they do not meet the rules, they will be sent back to the proponent to revise, so that it does comply.

What are the new consultation timelines that have been established with BRFN?

BRFN Lands will have 30 business days after the application is referred to provide initial comments on the application.

This sounds a lot like a joint review process with BRFN – does that mean BRFN is a decision-maker on permits issued by the BCER?

BCER and BRFN will work together to reach consensus on applications, but the BCER continues to be the statutory decision-maker on any applications. This commits both the BCER and BRFN to finding a new way of working together.

What are the timelines for this new process and for consultation – does it mean that it will take longer for the BCER to issue permits?

  • The court case meant there had to be a new way of doing business and the BCER has been working for months to get to this point in implementing the Agreement.
  • While there’s a timeline for initial responses (30 business days), there is no specific timeline to close consultation. The BCER also consults with other nations and will continue to ensure consultation is carried out meaningfully.

Is there any additional work remaining between the BCER and BRFN, with respect to finalizing the new consultation process?

While an important milestone has been reached in developing a new consultation process, there is still some outstanding work remaining, including further discussions on co-development of permit conditions, as well as the release of Regional Strategic EA (RSEA) information and refinement of the provincial cumulative effects support tool to inform decision-making.

Does this new consultation process extend to other Treaty 8 Nations or is it specific to BRFN?

This new consultation process is specific to BRFN.

How will the BCER determine which Treaty 8 Nations to consult with? Have the consultation boundaries that BCER and the Province use to consult T8 Nations changed as a result of the negotiated agreement.

No. The consultation boundaries remain the same as they were before this Agreement was signed. The consultation boundaries the BCER uses are derived from agreements with specific First Nations or from provincial guidance. Consultation boundaries are confidential between each nation and government, please contact at the BCER to obtain a list of nations in your key areas.

Is consultation with a First Nation expected on applications for projects located on private land?

The approach is unchanged from current process, where companies are required to pre-engage with First Nations for all applications located on private and Crown land.

Will there be timelines around consultation re-instated? Or will the timelines remain open with a lower volume of applications being referred to each nation.

There are timelines within the BRFN agreement. At this time, there will continue to be no set consultation timelines with other First Nations, although this is something the BCER will be discussing with each nation, as revised consultation processes are established in the coming months. This highlights the importance of meaningful pre-engagement by companies with nations, prior to submitted an application to the BCER.

If consultation and or pre-engagement continues past year end, does a company lose its tenure-based allocation?

If, due to circumstances beyond their control, such as lengthy consultation or application review, BCER was unable to make a decision on an application before the end of the year, the BRFN IA provides the flexibility to allow unused disturbance to be carried over to the subsequent year.

Presentations to provide additional information

Disturbance Cap Allocation - Approach and Next Steps

How long will the development caps be in place?

  • The Implementation Agreement does not specify a timeline for New Disturbance caps; however, as planning initiatives are completed, the caps will require some adjustment.
  • The caps will be reviewed annually by BRFN and the Province to determine if restoration and planning has progressed sufficiently to consider adjusting the caps. There is a comprehensive review scheduled at three years from the Effective Date of the Implementation Agreement that will consider whether caps, among other provisions, remain relevant and should be revised or continued.

How were the disturbance caps for each area determined?

Caps were determined through negotiation with BRFN. The overall Claim Area cap is approximately half of the historical average New Disturbance and regulate the pace of development while the more comprehensive cumulative effects management framework is developed and implemented.

How will the disturbance allocation work for individual companies?

The agreement established a cap on new disturbance as one component of managing cumulative effects while planning is undertaken. Tenure allocation under the new disturbance cap will be based on a number of considerations. A portion of the cap will be allocated to all companies holding at least two per cent of the Montney tenure in the area. The remaining portion will be allocated in a principled way at the discretion of the BCER. The BCER will work with individual companies regarding their priorities and in determining which applications will be adjudicated in a given year. Additional information on the allocation approach and principles will be communicated with industry and companies soon.

Will there be opportunities to go above the disturbance cap that has been put in place?

There are a number of provisions in the Implementation Agreement that provide for exceptions and flexibility to the cap regime.

Will the B.C. government consider additional disturbance allocation if a proponent is required to meet a setback requirement or avoid a sensitive environmental/cultural value?

If there is disturbance proposed for an activity, it will be counted towards the allocation regardless if there is an avoidance issue being considered. BRFN may agree to exceptions on a case-by-case basis with the proper pre-engagement and rationale.

Are electricity transmission and distribution lines subject to "New Disturbance" cap?

Outside of Area 1, electricity transmission lines do not count toward the New Disturbance cap. Within Area 1, BRFN must consent to the transmission line’s exclusion from the cap.

What constitutes “existing Disturbance”?

“New Disturbance” means, all (and only) Oil and Gas Activity-related disturbance on Crown land outside of any permitted and existing PNG footprint as identified in the SLU Data Layer,
including restored wells with a certificate of restoration but excluding: (i) restoration
activities; (ii) Health and Safety Activities; (iii) Environmental Protection Activities; (iv)
electricity transmission and distribution line rights-of-way outside of Area 1 or inside Area
1 with the consent of BRFN; (v) new operational activities within existing oil and gas
related disturbances or other permanent road structures (including, without limitation,
new wells on existing pads and pipelines within established rights of way); and (vi)
conversion of non-status roads to oil and gas roads, so long as such conversion does not
include any new construction or road modification.

What types of linear disturbances are subject to the 35km per year limit in Area 1?

    • According to the BRFN Agreement, this would apply to any new linear disturbance in respect of oil and gas activities which is not over, under or immediately adjacent to an existing linear disturbance or permanent road infrastructure.
    • “Linear Disturbance” means, subject to any and all limitations and exclusions provided for in this definition, any seismic line, road or pipeline on Crown land within the Claim Area which is regulated by a Provincial decision maker under the Oil and Gas Activities Act, S.B.C. 2008, c. 36 and/or for which the approval of a Provincial statutory decision maker under the Oil and Gas Activities Act is required for installation and/or operation. New Linear Disturbance is any of the above activities that are not over, under or immediately adjacent to an existing Linear Disturbance or permanent road infrastructure.

Does temporary workspace associated with operations or construction being carried out within an existing pipeline ROW count as “new disturbance?” The excel sheet had it included as an example, but it was associated with a new pipeline. Is temporary workspace always considered a new disturbance, or only when it is associated with new disturbance construction?

The existing pipeline ROW isn't new disturbance, but the new ancillary areas and new workspaces are considered new disturbance.

Is there a tenure allocation for sub region 1, based on the proportions of tenure within that area? Or can the broader allocation be applied in any of the sub-regions?

Tenure allocations and discretionary allocations must total the amounts specified in the BRFN Implementation Agreement (BRFN IA) and must be used within each designated area they are assigned to. Allocations cannot be moved between areas with caps.

When you refer to the “North Montney and Heritage Montney fields”, is this everything within the claim area?

The Claim Area defines the area within which the BRFN Implementation Agreement applies. The North Montney and Heritage Montney are names used to describe the Montney play trend north and south of the Peace River, respectively.

Do you want to see all development through to 2025?

Development should be shown for two to three years, so that the BCER can understand how critical applications are to the overall development planning within an area.

If a company received discretionary allocation for an application / bundle of applications, is the company free to use that allocation on other applications that may better fit their plans?

The BCER has evaluated proposed projects / application bundles from each company against the principles identified in OIC 354. Projects received discretionary allocation if they were the top performers in this evaluation. Therefore, it is important that the BCER ensure projects ultimately permitted under discretionary allocation reflect this assessment. Therefore, the BCER will require that alternative projects perform the same or better in BCER assessment vs. the principles set forth in the OIC in order to be put forward under discretionary allocation in place of the originally allocated project.

If a company received discretionary allocation for an application / bundle of applications and the company believes they can build the project with less disturbance than allocated to the project, could the remaining area be used by the company for another project?

In this circumstance, the company would need to revise their application for the project that received discretionary allocation to reduce the planned new disturbance. Then the company would be free to use the residual discretionary allocation area for another project.

Will the discretionary allocations provided to companies be made public?

No. The BCER does not plan to release this information publicly.

For column G - how detailed would you like this to be – would you like just the associated powerline and pipeline included, or are you wanting it more detailed to include which plant it will be flowing to, and which sales/liquid pipelines the product will be going through? Associated borrow pits and POD’s as well?

The submission should include all the activities that require applications to and permits from the BCER.

For column O – are you asking for what percentage of the Crown disturbance is existing for that application?

The submission should include the percentage of the application that utilizes existing disturbance, as defined in the BRFN IA.

For column Q – what is an “exception” considered in this context?

The reference to exceptions is with respect to Article 14.9 of the BRFN IA, which states that BRFN may agree to waive or otherwise amend on a permit or area by area basis, the provisions of Article 14.

Gantt chart – Are you wanting this broken down by tenure number, and if yes, do you know for what purpose? Do you want the duration of activity for each permit?

The submission should include a higher-level Gantt chart showing well pads, roads, pipelines, those types of activities that require disturbance and how the plan fits together from a timing/sequencing perspective. Breaking things by tenure number is not needed.

Regarding the allocation of capital investments per hectare of new disturbance – the guidelines indicate that dependencies will include sunk costs, but this could have a broad interpretation from sunk costs on the existing well pad through to sunk costs on the entire disturbance chain including initial seismic, roads, pipelines, facilities etc. Can you please clarify what the intended inputs for this calculation should include from the BCER perspective.

Sunk costs will be measured by the infrastructure investments dollars per hectare of permitted or tenured surface land associated with the development.

The BCER’s approach to assessing capital investment will conform to the guiding principles provided by the Province and with any subsequent directions or enabling regulation provided.

At present, the BCER will be considering sunk costs associated with the development directly related to the proposed new disturbance. Some examples are:

  • In relation to an application to construct a flow line and associated infrastructure to tie in existing wells, the sunk costs will include investment to date associated with the existing wells and the proposed new pipeline and associated infrastructure.
  • In relation to applications to construct a subsequent well pad that ties into an existing processing facility, the sunk cost will include investment to date associated with the new flow lines and associated infrastructure and the new well pad, as well as the existing facility.

The sunk costs would not include costs not wholly tied to the proposed application. Any costs associated with the subsurface tenure or other existing or proposed development of the subsurface tenure are not included in the calculation of sunk costs. In addition, sunk costs would not include non-capital expenditures (such as operating costs for infrastructure maintenance).

The guiding principles provided by the Province specify that consideration of dependencies will “include” sunk costs (as outlined above). An applicant may choose to submit additional information regarding dependencies related to the development proposal, for consideration by the BCER.

Questions relating to the calculation of sunk costs in relation to an application may be directed to:

Does BCER have a shapefile, or Google earth kmz file to share or if there is a layer in iMapBC that shows the claim area boundary?

Spatial information on the Agreement is available to download in KML, shapefile, and file geodatabase (FGDB) formats. An FTP client is needed to view these files: ementation_Agreement

Can projects that lie within an HV1-C region be part of the tenure or discretionary based disturbance cap allotment? Or will projects that lie within an HV1-C region only be approved as part of EMLI/BCER’s ongoing development planning pilots?

Projects that overlap an HV1-C polygon are not eligible for tenure or discretionary based disturbance cap allocation. Applications which propose New Disturbance in HV1C will not be considered during HV1 planning and must be consistent with an approved HV1 development plan. Applications within HV1C, which do not create any New Disturbance, may be considered. Ministry of Energy, Mines and Low Carbon Innovation is the lead accountable Provincial agency for the HV1C Plans and is working to complete the plans on the timelines identified in the BRFN IA.

Do proponents of a permit have the ability to designate a given permit to be considered under the tenure or discretionary based allotment? For example, choose which is considered for each allocation?


Is the worksheet to include only Crown land activities within the claim area or is the BCER requesting all applications regardless of location/Crown land/private land?

Crown land only, as the disturbance caps in the BRFN IA only relate to Crown land. However, for an integrated Crown/private land development plan, you may want to include private land applications in the description and Gantt charts for BCER’s clarity.

Do linear disturbances include roads?


Can you explain column R which reads “Is this development part of a broader plan already reviewed with First Nations/BCER”?

This allows an applicant to identify the degree to which it has engaged a Nation and/or the BCER (specify which one) to consider how the application fits within a broader plan and how the applicant has incorporated any feedback received.

Is the capital investment column only required for Crown discretionary allocation or all allocation?

Crown land only, as the disturbance caps in the BRFN IA only relate to Crown land. However, for an integrated Crown/private land development plan, you may want to include private land and itemize separately for BCER’s clarity.

If we have a facility amendment in with the BCER or plan to submit, should this be captured?

This review process includes all existing applications or planned applications that require new disturbance.

Are Section 10 applications to be stated?


Are powerline rights-of-way within the claim area south of the Peace River to be captured?

While powerlines outside of Area 1 do not require new disturbance under the allocation, knowledge of this in the development plan would be useful.

On the disturbance table, if there is no pad and only a pipeline, are we to state only the pipeline?


What about new disturbance activities that do not fall under the environmental or safety aspect. Examples include slope stabilization, where workspace is required to mitigate a potential problem that could affect the integrity of the pipeline. The concern focuses on unforeseen preventative maintenance items. Should industry be planning to save some allocated disturbance for these unforeseen maintenance requests? Or is there a mechanism for discretionary allocation based on supporting existing production?

The BCER expects that most activities needed to address slope stability concerns relating to infrastructure integrity, will fall under the definition of “environmental protection activities” or “Health and Safety Activities”, and thus would be excluded from the definition of “new disturbance” and would not require allocation.

Activities that meet the definition of “new disturbance” will require allocation. The BCER will consider these applications for discretionary allocation among other proposed activities.

What occurs if an oil and gas company purchases a permitted forestry road and does not do any upgrades on it? Is it considered a new disturbance and therefore part of the allocation process?

Forestry roads are not an exemption under the New Disturbance definition. Forestry roads converted to oil and gas roads are “new disturbance.

Could 2024 discretionary allocations be given before tenure-based allocations are calculated, to facilitate the issuance of permits needed - for example - in early January 2024?

The BCER is in the early stages of designing the allocation process for 2024 and will be in a better position to communicate next steps once the process for 2023 is completed, and additional discussions with the Ministry have occurred around tenure allocation for 2024.

Will allocation amounts be disclosed by Gov or BCER to Nations/other companies/the public?

Currently, it is not the intent of BCER to publicly disclose disturbance allocations.

Are work areas associated with powerlines considered as a new disturbance?

Outside of Area 1, they can be excluded as a “New Disturbance” s1.1(oo)(iv). Inside Area 1, consent will be needed from BRFN in association with the powerline s1.1(oo)(iv).

What is the application process and considerations for footprint for temporary workspaces for non-emergencies?

Applications for workspace should be submitted through AMS and will be subject to regular reviews and consultations prior to decision. Workspaces needed for” Health and Safety Activities” or “Environmental Protection Activities”, as defined in the BRFN IA (e.g. integrity-related activities to address a slope failure at a pipeline creek crossing that threatens pipe integrity,) are excluded from the definition of “new disturbance” under the BRFN IA. As such, they will not require cap allocation prior to approval. Workspaces associated with new construction or amendment activities that are not related to safety or environmental issues, or powerlines outside of area 1, will require cap allocation prior to approval.

Members noted that the data sets currently available to assess existing disturbed footprint on the land does not map/inventory disturbances that are not associated with licenses. Accordingly, the data sets do not show the full extent to what existing footprint is available for development. This limits companies’ ability to prioritize and use existing footprint over creating New Disturbance to support their developments. Would it be possible to obtain data on all disturbances on the landbase to ensure and prioritized and optimal use of existing footprint?

The SLU data s1.1(eee) was released to industry and is available here:

  • Unless amended, this layer is to be used to delineate existing PNG disturbance.

Is the $200M BRFN Restoration Fund contribution additional to or inclusive of the $60,000 per hectare restoration fee levied on disturbances?


Will the $60,000 per hectare fee apply for any disturbance created to support maintenance and operation of an existing facility in HV1A Areas?

The fee applies to all “New Disturbance”.

To what areas will the $60,000 per hectare fee be applied?

This fee will apply to new Crown land disturbance within the HV1, Trapline and Priority Watershed Management Basin Areas.

Will industry be required to restore sites at an accelerated pace in HV1, and will these identified sites be made available publicly?

The agreement lays out requirements for priority site designations of dormant sites within HV1. The BCER is currently analyzing these requirements and will be communicating directly with affected companies.

Planning and Mitigation Measures for Activities in Treaty 8 Territory Frequently Asked Questions

1. The information update on January 15, 2024, referenced that the BCER will be organizing an information session to assist permit holders and operators in understanding the procedures and recommended practices involved in implementing these measures. Has this session been organized, and if so, was it recorded, or are the presentation materials available online?

An information session was held on March 8, 2024, it was not recorded but the presentation materials are available HERE.

The session was informed by the questions and feedback that we have received from industry since releasing the planning and mitigation measures in January.

2. Where do the planning and mitigation measures apply?

The planning and mitigation measures will apply across the Treaty 8 Territory within northeast British Columbia.

3. When do the planning and mitigation measures take effect?

Applications received after April 15, 2024, will be required to incorporate these measures prior to an application progressing to the consultation and decision-making phases.

4. How will the BCER use the planning and mitigation measures to inform their decision making?

Applications for permits and authorizations will not be progressed unless Applicants have demonstrated incorporation of the measures, where applicable. 

Where planning and mitigation measures apply, approvals may contain application specific conditions.  Conditions are legally enforceable.

5. Do the planning and mitigation measures apply to permit applications that have been submitted before the effective date but have not received a decision before the effective date?

If a permit application has been submitted prior to the effective date, a proponent will not be expected to retroactively incorporate these planning and mitigation measures. However, the planning and mitigation measures were derived from concerns and interests brought forward by Treaty 8 Nations during consultation on project applications, so it may benefit the proponent to be prepared to address these considerations during consultation.

6. If a project has received a permit but has not started construction prior to the effective date, should the proponent update management plans and design to reflect these planning and mitigation measures?

If a permit has been granted prior to the effective date, the proponent is not expected to retroactively incorporate these planning and mitigation measures.

7. How were the Treaty 8 Nations engaged in the development of the planning and mitigation measures?

The planning and mitigation measures were developed through engagement with the Treaty 8 Nations using a list of values and interests brought forward during ongoing consultation on project applications. Engagement included one-on-one meetings, email correspondence, and existing committees.

8. What is the process for collaboratively adapting or updating the planning and mitigation measures document?

Minor updates (for example spelling, editorial or clarity corrections) to the document will result in issuing a new version. If this were to occur, the summary of revisions will be described in the document revisions table.

Major updates or revisions (if required) would be done through consultation between the BCER, industry and Indigenous nations. The implementation of these changes would be date stamped and there would be a phase in period, like with the first version.

9. How do the planning and mitigation measures relate to the Consensus Document, Implementation Agreement, other measures of conditions for development plans and other draft development plans underway or to be finalized in the future?

The planning and mitigation measures are aligned with, but do not replace, requirements that may be outlined in the Consensus Document, Implementation Agreement and other plans. These measures support and operationalize many of the goals and objectives that are part of the Province's commitments made through these agreements.

10. Will there be a synthesis of the planning and mitigation measures, development plans and other new material into one document or website?

The BCER’s Oil and Gas Activity Manual will be updated to include the planning and mitigation measures and other material that applicants must implement during the planning stage. As with all applications, proponents are encouraged to become familiar with relevant acts and regulations and seek direction from BCER staff for clarification where necessary.

11. Will these planning and mitigation measures replace existing guidelines, such as the Environmental Protection Management Guidelines?

These measures do not replace existing guidelines (such as the Environmental Protection Management Guidelines) but add to and supplement those already in effect in the Treaty 8 Territory. Proponents and their contractors are encouraged to become familiar with the applicable acts and regulations and seek direction from BCER staff for clarification where necessary.

1. What is the best approach for a proponent if they are unclear if the planning and mitigation measures apply to their project?

If a proponent is unclear if the planning and mitigation measures apply to their project, it is encouraged they seek clarification from the BCER. To do this, a request should be submitted through the Contact page on our website and made to the attention of the Director of Authorizations

2. Are separate deliverable(s) required to be included with permitting applications, or can they be included in existing reports?

Separate deliverables, plans and/or drawings are not required to be included with permitting applications (unless explicitly noted). Where appropriate, the information describing the implementation of the planning and mitigation measures can be captured using existing materials.

3. How do the planning and mitigation measures apply on private land?

Land owners can request to have the planning and mitigation measures applied to projects on their private land. The measures do not otherwise necessarily apply on private land, except in cases where:

  • the project intersects with a stream (e.g., watercourse or wetland) and/or
  • the activity intersects with Crown land, in which case line of site mitigations would be required at that crossing.

4. Are the planning and mitigation measures applied to existing pipelines and facilities that are planning for reactivation?

If the reactivation involves new disturbance or affects one or more of the planning considerations (for example stream, wetland and lake crossing, mineral licks and wallows or air quality), then the proponent should be prepared to implement the appropriate and relevant planning and mitigation measures.

5. Do the planning and mitigation measures apply to facility applications on existing sites?

The planning and mitigation measures are relevant for facility applications (for example addition of compressor or new facility equipment) if a project activity is anticipated to affect one of the planning considerations identified in the document (for example stream, wetland and lake crossings, mineral licks and wallows or air quality).

6. Are the planning and mitigation measures expected to be used in all circumstances or will there be some discretion?

It is recognized these mitigation measures may not be practical or applicable in every circumstance, in every area or for every activity. If a proponent considers any measure(s) to be infeasible, they are expected to discuss their concerns with the affected Treaty 8 Nations during pre-engagement, propose alternatives and try to come to a collaborative solution.

As part of the application, applicants should describe how they have considered the measures in the planning stages, provide a rationale for why these measures were not applied, and provide reasonable alternatives to mitigate effects, as appropriate. The BCER requires pre-engagement through the Guidance for Pre-engaging with Indigenous Nations (Version 1.0, March 2023) with Indigenous nations to ensure the rationale and/or proposed alternative is appropriate.

7. How will the planning and mitigation measures inform a proponent’s pre-engagement with a First Nation? 

The purpose of the planning and mitigation measures is to provide insight on what to expect when preparing for and carrying out pre-engagement. The proponent should be prepared to address these considerations during pre-engagement.

8. Are mitigation measures outside of the planning and mitigation measures document to be expected? Under what circumstances would additional measures be expected?

Additional project-specific measures may be co-developed with specific First Nations through pre-engagement. If over time, through industry and Indigenous pre-engagement, existing planning and mitigation measures are found to be impractical, they may also be removed or adjusted.

1. Will requirements for managing impacts from air emissions be different for the operational and construction phases?

During the construction phase, the proponent should identify any plans or best practices that will be implemented to reduce air emissions from vehicle and heavy equipment engines, including but not limited to: minimization of equipment use, using cleaner fuels and optimizing maintenance schedules. The proponent should also identify how dust from construction activities will be minimized and/or mitigated.

The operational phase must quantify the criteria air contaminants that may be emitted during operation of the project. The proponent should be prepared to speak to the monitoring and measurement methods and impacts to air emissions for both phases during pre-engagement.

2. Is there guidance or instructions related to the air quality monitoring requirements outlined in the planning and mitigation measures?

The planning and mitigation measures do not replace existing guidance and instructional documents (such as The British Columbia Field Sampling Manual: Air and Air Testing Emissions Testing) but add to and supplement those already in effect in the Treaty 8 Territory.

3. How should the items listed under “Additional Project Planning Considerations” be incorporated into project planning?

The items listed under the section “Additional Project Planning Considerations” are important to keep in mind and consider when planning. These are not requirements but the proponent should be prepared to address these considerations during pre-engagement.

4. The planning and mitigation measures do not provide specific guidance, setbacks or monitoring requirements (e.g., line of site). How would a proponent understand what is an acceptable form of mitigation for their project?

A qualified environmental professional should complete an assessment of the project activities and determine the potential effects to environmental values and Indigenous values or interests. The proponent should be prepared to address these effects and propose mitigation measures during pre-engagement.

5. What are the expectations for wildlife monitoring for facilities?

The intent of wildlife monitoring at facilities is to identify if there are impacts from a facility on wildlife. Regular monitoring would be required (during peak activity periods) and if adverse effects are noted, adaptive recommendations should be proposed to mitigate effects. A possible example may be impacts of light on surrounding wildlife and a potential solution could be to angle lights in a different direction.

6. What needs to be included in the Wetland Hydrological Integrity Plan?

At minimum, the wetland hydrological integrity plan must include mitigations proposed to maintain the natural flow of the wetland. A qualified environmental professional should complete an assessment of the project activities and determine the potential effects to environmental values and Indigenous values or interests. The proponent should be prepared to address effects to wetland hydrological function and propose mitigation measures during pre-engagement.

7. What type of qualified professional is eligible to complete an assessment of the ecological and hydrologic functioning of a wetland and design the hydrological integrity plan?

A qualified environmental professional acting within their scope of practice per the Professional Governance Act (SBC 2018) and the Professional Accountability Policy (2019) can complete an assessment of the ecological and hydrologic functioning of a wetland and design the hydrological integrity plan.

8. Are there appropriate or approved line-of-sight mitigation measures?

Where new clearing intersects an existing seismic line or pipeline right of way that does not have a line-of-sight barrier, such as vegetation, woody debris piles or earthen berms of at least two metres in height across the area of the intersection, the proponent must establish a suitable line-of-sight barrier at the location of the intersection.

9. Are line-of-sight mitigation measures expected for a new right-of-way that parallels existing linear corridors (e.g., pipelines or roads)?

Line-of-sight mitigation measures should be considered if the proposed right-of-way parallels an existing linear corridor. Mitigation measures could include, for example, leaving vegetation or piling coarse woody debris (e.g., non-merchantable timber) between the two corridors.

Line-of-sight mitigation measures should also be considered in cases where the new right-of-way is contained within an existing, wider corridor (which may not have otherwise had existing line-of-sight mitigations).

10. Are line-of-sight mitigation measures expected at regular intervals for all new linear corridors?

It is expected that proponents incorporate line-of-sight mitigation measures at regular intervals across all new linear corridors. Early environmental overview assessments may be useful to determine the optimal intervals and locations for line-of-sight mitigations for a specific corridor. For example, mapping wildlife trails can inform the placement of line-of-sight measures to help maintain connectivity of the trails. This mitigation will be site-specific and informed during early assessments and pre-engagement.

11. Are restoration activities considered a separate project or an associated activity within the proposed project?

Restoration activities are considered an associated activity within the proposed project. They are not considered a separate project and a separate application is likely not required.

12. For pipelines, a rationale is required to justify the width of the right-of-way needed for ongoing operational activities according to the CSA Z662 standards. Is this rationale required only if width is greater than that specified in CSA Z662?

A rationale for the width of the right-of-way needed for operational activities (e.g., access, safety, maintenance and surveillance) is required for each new pipeline application. In some circumstances, there may be opportunities for restoration of certain areas, or the width of the pipeline right-of-way needed may vary to support operational activities. For example, if an engineer considers it safe, there could be opportunities for narrowing or for vegetation to grow on the right-of-way. Other mitigations may include employing meandering access areas (instead of a straight line) as a line-of-sight measure.

13. Does interim restoration change areas allocated as New Disturbance? For example, will there be a plus and minus to the allocated New Disturbance based on interim restoration area?

Interim restoration activities do not change the area allocated as New Disturbance.

ePayment Frequently Asked Questions

What is ePayment?

ePayment is the Regulator's secure online portal used to electronically pay for various fees and levies using Electronic Fund Transfer (EFT). ePayment can be accessed here in the Online Services section of the website.

What is Electronic Fund Transfer (EFT)?

Electronic Fund Transfer (EFT) is an electronic transfer of money from one bank account to another. It should be noted that although the Regulator uses a Pre-Authorized Debit (PAD) agreement. Each payment is initiated by the applicant's ePay Payer security role before payment is made.

Can I choose to pay with my credit card?

No. The Regulator does not accept payment by credit card.

What is required to setup an ePayment account?

In order to setup an ePayment account the Regulator requires the following documents to be submitted:

  • A letter, on company letterhead, sighed by a company executive (for example a CEO, CFO, or VP) authorizing a person to be designated as the ePay Financial Admin. An example letter of authorization can be found here.
  • A Pre-authorized Debit (PAD) agreement form.
  • Either a void cheque or signed letter from the company’s banking institution confirming the validity of the banking account information.

Please note, a company can only hold one EFT account with the Regulator.

My company does not allow PAD-based EFT due to fund control. Are there alternatives?

No. Payments are user-initiated and staff that are assigned the ePay Payer role must select an invoice and go through the payment process before the transaction is submitted to the bank and money is debited from the company’s account. The Regulator cannot authorize funds to be removed from a company's account.

My company doesn't provide PAD information without being released from liability in case of fraud. Does the Regulator sign indemnity agreements?

No, the Regulator does not sign indemnity agreements.

Who do I contact with questions about filling out these documents?

Please contact a finance representative at the Regulator via email at We will respond to you via email within two business days.

Where should I send the documentation?

This documentation can be emailed to the Regulators finance department at however please note that email is not considered a secure form of sending information. To ensure your privacy and security please mail or courier the information to the following:

Mail Address:
Attention Finance Department
PO Box 9331
Stn Prov Govt, B.C.
Victoria, B.C. V8W 9N3

Courier Address:
Attention Finance Department
2950 Jutland Rd
Victoria, B.C.
V8T 5K2

What roles exist in ePayment?

Users can be assigned one, or more, of three different roles associated with ePayment. The roles are:

  • ePay Financial Admin: This role is the administrator for the company EFT account. Users assigned this role are able to manage and update the EFT account and assign up to three payment level authorizations to users with the ePay Payer role.
  • ePay Payer: This role is assigned to users who are able to review invoices and make payments. Users with this role must be provided an Authorization Code by the ePay Financial Admin that enables them to make a payment up to a maximum amount.
  • Applications: This is an existing role in KERMIT that carried over to AMS system when it launched. Company Administrators will continue to assign this role to users who will prepare and submit applications. This role allows users to view invoices in ePayment but not to edit financial information or make a payment.

A summary of the roles is below:

ActionsePay Financial AdminePay PayerApplications
Edit EFT Account

(non-financial data)

View Payment TransactionsYesYesYes
Register Payment to Pay LaterYesYes
Submit PaymentYes
Resubmit Failed PaymentYes

Can I have financial roles with more than one company?

No. Each account can only be assigned the ePay Financial Admin for one company. However, ePay Payers can be assigned to more than one company.

Is it possible to have two ePay Financial Admins on an account?

Yes, a company can assign two ePay Financial Admin users as joint users.

My company provides funds to Land Agents to pay applications. Can Land Agents still pay on behalf of the company without accessing the bank information?

Anyone that is assigned an ePay Payer role can pay an invoice on behalf of the company. This role is assigned by the ePay Financial Admin.

How do I limit the payments that an ePay Payer can make with my bank account?

The ePay Financial Admin role can set up to three authorization codes each with a maximum payment limit for payments to be submitted to the Regulator by the ePay Payer role. To do this, the ePay Financial Admin role must log onto ePayment, click "Edit EFT Bank Information” in the far left navigation panel. The resulting screens will enable the ePay Financial Admin to set three maximum payment amounts and Authorization Codes.

What if I am not authorized to pay the full amount of my invoice?

The person in your company who is assigned the ePay Financial Admin role can assign ePay Payer roles in KERMIT. The ePay Payer roles are assigned a maximum amount they are allowed to pay. If you cannot submit a payment, please check with your ePay Financial Admin on whether your maximum amount needs to be adjusted.

ePayment is asking me for an Authorization Code. Where do I find one?

The Authorization Code is assigned by the ePay Financial Admin role. If you do not have an Authorization Code, check with your ePay Financial Admin. The ePay Financial Admin role is able to create three Authorization Codes in the EFT Account details screen in ePayment.

I saved my username and/or password on your site. How do I clear this information?

If you have saved your login credentials on our online system please contact your IT department for assistance in clearing this information.

How do I log out?

There is a log out button at the top right of ePayment. Always use the log out button to ensure your session is properly closed.

What does it mean when my session times out?

ePayment keeps track of periods of inactivity. If you are inactive on the site for 15 minutes your session will expire and you will be required to log in again. This is a security feature to ensure your identity and information is protected.

Why do I need to clear my browser cache?

As a security measure it is recommended that you clear your browser cache ensuring that your information remains private.

Will I get a receipt when I pay online?

Yes. When an online payment is submitted, the invoice will automatically be updated to include payment details for your records.

How long does it take for a payment to be transferred?

EFT payments are processed from your financial institution within two business days.

Can I access previous invoices?

Yes. Previous invoices are listed in the dashboard of ePayment.

Do I have to pay as soon as an application is submitted?

No. Companies have 30 days to pay an application fee invoice.

How is the financial information secure and protected?

Regulator online systems use industry best practices to protect all information collected. Secure transfer protocols are used to encrypt data sent back and forth between system users and the Regulator’s service. The EFT information is only viewable and editable to certain security roles assigned by the company.

However, as a user there are certain precautions to employ to keep your information private:

  • Always keep your user name and password secret and never save them in your browser.
  • Log out and close your browser after every session.
  • Clear your internet browser cache after each session.

Does the Regulator automatically debit the accounts for unpaid invoices?

No, the Regulator cannot debit bank accounts. Users with the ePay Payer role initiate the payment. The Regulator then batches all initiated payments once a day and submits them to the bank for processing.

Does my account have to have a minimum balance?

No, the account only needs sufficient funds to make a payment when your ePay Payer initiates the payment.

How do I set up Authorization Codes?

The ePay Financial Admin role is able to set up to three Authorization Codes to enable an ePay Payer to make a payment. A Quick Reference Guide to doing this is here.

How do invoices work for amendments?

Amendment invoices are generated in ePayment and an email notification is sent after the decision maker has made a determination on an amendment application.

Facilities Frequently Asked Questions

If we have a permitted wellsite and are planning to install equipment at the well as part of the operation of the well is that equipment considered a facility?

Yes, the equipment addition at the wellsite would fall under the facility type “Well site Facility,” and a facility permit would be required prior to the equipment installation.

For a facility permit, or amendment, in the Emissions Air Details section of the AMS application are the volumes fields applicable for the new installation scope only, or do they require the volumes for the entire facility, including what already exists?

All volumes should be cumulative (existing and proposed) of all equipment associated with the applicable Facility ID.

High level and high pressure shutdown devices. What are the rules for when, and where we need to install high pressure and high level devices on pressure vessels, and storage tanks?

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, and 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.

Under the section 'Flaring and Venting' in the AMS facility application a venting rate is required. Does this application field require the venting rate for the new equipment installation scope, or does this question require the venting rate for the entire site including what is already existing?

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

Is there any equipment combination that would not require a facility permit or amendment application?

Appendix “D” of the Oil and Gas Activity Application Manual lists facility changes where neither an amendment, nor a Notice of Intent (NOI) is required. For more information on when a permit amendment is required for changes being proposed at a facility, please refer to Chapter 4.3 of the Oil and Gas Activity Application Manual, or Chapter 12 of the Oil and Gas Operations Manual. For more information on this particular topic, including short term equipment installations of equipment at existing facilities, such as small booster compressors for testing purposes, etc., feel free to contact the Facility Engineering Application team by email at

If we have an existing well with a facility permit already in place, and a second well on the same lease is proposed, do we require a new facility permit for the second well, or will a facility amendment be sufficient?

This scenario would normally require a Facility Permit Amendment submitted through the Application Management System (AMS). The second well facility could also be applied for with a New OGAA Application, if preferred.

If metering equipment is proposed at a well, would a facility permit application be required?

Generally, all new metering installations or changes to measurement at a well, or at an existing well facility, where the equipment will be used for production accounting, delivery point, or custody transfer purposes will require a permit or permit amendment.

Can quantification of venting/flaring volumes at well sites for application and reporting purposes be carried out using estimation vs metering?

Yes. Refer to the Measurement Guideline for Upstream Oil and Gas Operations for additional information. Also refer to section 4.3 of the Oil and Gas Activity Application Manual for guidance on how to enter this information when submitting an application or amendment through the Application Management System (AMS).

The Application Management System (AMS) asks if a facility will recover low pressure vapours. How should this question be answered if vented gas is being sweetened and vented to atmosphere and not recovered?

The question would be answered, “No” in this instance, as the vented and sweetened gas is not being recovered, but vented to atmosphere. 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.

Liability Management Program Frequently Asked Questions

Where can I find the electronic/wire transfer information to submit the required security?

Please have your banking institution contact the Regulator directly at to request this information.

Who should my letter of credit or cheque be made payable to and where do I send it?

The letter of credit beneficiary and cheques are payable to, BC Energy Regulator.
Security deposits are to be couriered to:


What will happen if I can't or won't pay?

Permit holders who fail to submit required security deposits within the allocated timeframe may be in noncompliance with Section 30 of OGAA. If the security deposit was required to approve a permit transfer application, the application will not be approved. If the security deposit was required under an initial or monthly assessment, additional compliance action will be taken against the permit holder. This may result in the cancellation of permits or orders to cease operations.

In what format does the Regulator accept security?

Security deposits will be accepted as a certified company cheque or electronic/wire transfer, from a recognized Canadian financial institution, or as an irrevocable letter of credit from a Canadian Schedule I or Schedule II bank, a Canadian Credit Union, the Caisse Desjardins, or the Alberta Treasury Branch. Please note, letters of guarantees, safekeeping agreements, performance bonds, and personal cheques, will not be accepted.

When will my security deposit be returned?

  1. The Regulator may, upon request by a permit holder, return all or part of a security deposit when the permit holder has completed liability reduction activities (decommissioning or obtaining a Certificate of Restoration Part 1 or Part 2) and the security is not required to secure the permit holder's obligations.
  2. The security deposit will be returned in full when all the restoration obligations associated with a permit holder’s sites are brought to closure.

Will interest be paid on an operator's security deposit when it is returned?

No, interest will not be paid. Only the amount that was held as security will be returned. This policy was rolled over from the Ministry of Finance administration.

Will I have to pay a security deposit to transfer permits?

Upon receipt of an application for a permit transfer of one or more wells and/or facilities, both the transferor and the transferee will be subject to a security requirement review. As part of the security requirement review, the applicant and permit holder will be requested to submit their most recent Financial and Reserves information.

The applicant or permit holder involved in the transaction may be required to submit a security deposit as calculated by the Regulator. In addition to the requirement to maintain an immediate post-transfer LMR above 1.0, decisions on security deposit requirements may be based on the submitted financial and reserves information and associated compliance issues. Security deposits are to be submitted within 30 days from the date of request.

Will the program eventually eliminate Orphan wells?

It is the intention that the LMR 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.

Why do a number of my cancelled wells have a reclamation liability assigned to them? There was never a well drilled onsite.

A drilling event may not have occurred on the lease; however, the Regulator has reason to believe that construction had started (e.g. clearing, road construction, cut/fill, etc.) Therefore these wells have been flagged ‘cancelled with surface disturbance’ and will require restoration work be completed in order to have a Certificate of Restoration issued.

Do you take into account working interest participants (WIPs) when assigning deemed liability and production assets of a well?

No. At this time WIPs are not taken into account. Under the program the permit holder of the site holds 100% of the deemed liability and production assets.
Why not?
Because WIPs are frequently changing we are unable to consistently keep our records current enough to tie into the LMR program. Ultimately, the permit holder is held responsible by the Regulator.

My deemed well liability has increased since last month, but we haven't drilled or acquired any new wells. How did that happen?

A number of things may have happened.

  1. A surface casing vent flow/ gas migration issue was identified, therefore a premium is added to the wells individual deemed liability.
  2. A drilled/cased well completion has been entered into the Regulator database.
  3. A cancelled wellsite was later identified as being cancelled with surface disturbance.
  4. A well previously never having produced/injected, does so.

Other than divesting, how can I reduce our deemed liability?

Complete abandonments: Deemed liability will decrease when a well is abandoned and the appropriate documentation is submitted to and approved by the Regulator
Apply for a Certificate of Restoration (CoR): The deemed liability assigned to a site will be removed when the wellsite is reclaimed and a CoR is issued.
Terminate a facility: A Facility’s deemed liability will only be removed when a facility is decommissioned, removed from site and terminated in the Regulator database.

More information on the dispute process and site-specific liability assessments can be found in the LMR Program Manual:

The Regulator may require a site-specific liability assessment for one or more permits to be used in the calculation of an operator’s LMR or, in the case of a problem site, for the determination of a required security deposit. The only time an operator may make the choice to submit a site-specific assessment is as part of a security deposit dispute process. As part of the process an operator must submit for review, along with a operator specific netback calculation, site-specific liability assessments completed by a qualified third-party professional for each well and facility permitted to the operator. More information on the dispute process and site-specific liability assessments can be found on pages 16 and 17 of the LMR Program Manual.

We note that the program is similar to the AER program in Alberta. Is there an attempt to harmonize the 3 western province's liability programs?

The Regulator works closely with other regulators in Alberta and Saskatchewan to align liability management programs where appropriate. The Permittee Capability Assessment (PCA) is being developed in collaboration with the Alberta Energy Regulator’s development of their Licensee Capability Assessment (LCA).

Industry has considerable knowledge and experience on liability costs as a result of the Alberta system. Will there be an opportunity for further industry consultation?

The Regulator has continuously engaged with stakeholders in the update of the liability model and the development of the Permittee Capability Assessment. The Regulator is always open to feedback from stakeholders regarding our programs.

What tool will be put in place so that an operator can monitor their liability rating?

LMR ratios for BC operators are posted to the Regulator’s website here. Ratios are calculated and updated daily.

The Regulator has developed a report that lists the deemed assets and liabilities for each individual well and facility permit held by an operator. To access these reports visit Data and Reports, then Data Centre and select Liability Management reports from the list on the left-hand side. Operators that would like to obtain information on their security deposits can send a request to

Northeast Watershed Assessment Tool (NEWT) Frequently Asked Questions

How do I access NEWT?

NEWT can be accessed via the following link

How do I search via the map?

  1. Use the pan and/or navigation buttons to find the desired location on the map
  2. Select the “Identify with tools” button, then use the “Select” tool
  3. Click a location on the desired stream or lake. The upstream watershed area will now be displayed with a red outline and crosshatched interior.
  4. The NEWT tool box will now display the selected watershed results, click result to zoom to the selected watershed.
  5. By default, the “Report Title” on the NEWT tool box will be filled in. This can be changed if desired. The report can now be exported in either PDF or CSV format.

How do I search via UTM coordinates?

  1. Select the “Enter Values Manually” tool
  2. Enter the UTM coordinates for one or more points in the format of Easting, Northing (eg. 516410, 6630377)
  3. Select submit
  4. The watershed area(s) will now be displayed with a red outline and cross hatched interior.
  5. The NEWT box will now display the watershed results. If you entered multiple points there will be multiple watershed results listed. Click on a watershed to zoom to zoom to it.
  6. By default, the “Report Title” will be filled in on the NEWT tool box. This can be changed if desired. The report can now be exported in either PDF or CSV format.

How do I get support?

For further assistance with NEWT please email An email to this account will generate a call number, which will be emailed back to the submitter for future reference.

Oil and Gas Processing Facility Regulation Frequently Asked Questions

Where can I find answers to some of the most common questions about the Oil and Gas Processing Facility Regulation?

Answers to some of the most common questions received by Regulator staff since the Oil and Gas Processing Facility Regulation (Regulation) came into effect on March 4, 2021 can be found in the dropdowns below or in this PDF: Oil and Gas Processing Facility Regulation Frequently Asked Questions. It has been updated to include additional questions from Indigenous nations and industry stakeholders during May and June 2022.

Please note these FAQs and any other subsequent guidance documents are not intended to replace regulation. For more information about the regulation, please visit

Will the Regulator issue guidance?

Yes, the Regulator develops guidance to support its decision-makers and to ensure transparency in the administration of oil and gas activities. This draft guidance was released for feedback in April 2022 and a revised version published in October 2022. Proponents are already looking ahead to ensure their new, contemplated developments, and amendments to existing ones, meet the expectations of the Regulator under this new regulation. The Regulator has engaged, in advance of the issuance of this new guidance, with First Nations who have existing or proposed facilities within their territories.

How does the Guidance reflect the Regulator’s expectations of oil and gas proponents to incorporate Indigenous Knowledge and work differently with Indigenous Nations?

The Regulator is committed to continuing to build mutually-beneficial, collaborative working relationships with Indigenous communities and to ensure the interests of Indigenous Peoples are understood, respected and considered in Regulator decisions and the delivery of the Regulator’s mandate.

This guidance document provides guidance to oil and gas proponents that supplements the requirements of the Oil and Gas Processing Facility Regulation. It describes the Regulator’s expectations of proponents for working with Indigenous nations, including for Assessments of Social and Cultural Effects, Assessments of Environment Effects, incorporation of Indigenous Knowledge, and for Pre-Engagement with Indigenous nations.

How does the Guidance meet the considerations of the Declaration Act and the United Nations Declaration on the Rights of Indigenous Peoples?

The Regulator is named specifically under Action 2.6 of the Declaration Act Action Plan: Co-develop strategic-level policies, programs and initiatives to advance collaborative stewardship of the environment, land and resources that address cumulative effects and respects Indigenous Knowledge.

The Regulator is committed to working collaboratively with Indigenous Peoples in the development, design, engagement and review of any improvements to the Oil and Gas Processing Facility Regulation, and related guidance documents. The Regulator continues to build mutually-beneficial, collaborative working relationships with Indigenous communities and to ensure the interests of Indigenous Peoples are understood, respected and considered in Regulator decisions and the delivery of the Regulator’s mandate. Engaging with Indigenous Peoples throughout the regulatory lifecycle reflects the holistic approach the Regulator takes to consider connections between land, Indigenous rights, self-determination and cultural identity. This work supports the Regulator’s obligation as a Crown agency under Section 3 of the Declaration Act to bring provincial laws into alignment with the UN Declaration. Refinement will continue as the experience of applying the regulation evolves, with continued input from Indigenous Nations.

What are some of the key highlights in the Regulation?

The Regulation sets out pre-application requirements, regulates operations by emphasizing safety, addresses the end-of-life stage requirements for safety and the surrounding environment and requires consistent methane reduction provisions, as described in the Drilling & Production Regulation for other facilities. It also contains new requirements for the completion of social and cultural effects assessments and the incorporation of Indigenous Knowledge in permit applications.

Industry Bulletin INDB 2021-10 sets out a further summary of the Regulation’s key points.

What is a qualified professional as referenced in the Regulation?

The Regulation defines a qualified professional as follows: a person who is authorized under the Engineers and Geoscientists Regulation to use the reserved title “professional engineer” or “professional geoscientist”. The Regulator will be expanding this definition to include other applicable registered professionals such as biologists or agrologists, primarily for specific requirements in the Regulation where environmental expertise is needed.

How will feedback continue to be considered for the Guidance over time?

The guideline describes the Regulator’s expectations of oil and gas proponents regarding how to meet the requirements of the new Oil and Gas Processing Facility Regulation. As a result of the feedback on the draft guidance document, Regulator staff have refined the language in the document to clarify these expectations.

The Regulation itself, in effect since March 2022, is not under review at this time but feedback is encouraged at any time, and will be considered in future revisions.

How have expectations for engagement with First Nations changed under the Regulation?

The new requirements have formalized expectations for including Indigenous Knowledge in environmental, social and cultural effects assessments and related reports. These expectations are likely to evolve as the Province works toward reconciliation with Indigenous People to ensure a modern interpretation for the respect of existing agreements and treaties.

Reference documents regarding the First Nation consultation process and the applicant’s role are available on the Regulator’s website. Applicants may also refer to the Ministry of Indigenous Relations and Reconciliation’s Building Relationships with First Nations: Respecting Rights and Doing Good Business and Guide to Involving Proponents When Consulting First Nations.

How should proponents identify which First Nations should be engaged with?

Proponents can use the Province’s tool for guidance (Welcome to PIP: Consultation Areas ( However, proponents are encouraged to contact the Regulator for recommendations about pre-engagement with First Nations.

How could the Consultative Areas Public Map be used by proponents?

The link to the Consultative Areas Public Map in the guidance document is provided for reference, and contains a disclaimer that lets proponents know information provided in the map is based on the current information made available to the Province.

The information provided is not intended to create, recognize, limit, or deny any Aboriginal or treaty rights, including Aboriginal title that First Nations may have, or impose any obligations on the Province or alter the legal status of resources within the Province or the existing legal authority of British Columbia. The Province makes no warranties or representations regarding the accuracy, timeliness, completeness, or fitness for use of any or all data provided in the reports.

How far in advance should proponents begin pre-engagement with Indigenous Nations?

In an effort to include Indigenous Knowledge in project planning, pre-engagement with First Nations should start as early in the planning stages as possible. A reasonable timeframe is at least 90 days before an application is submitted to the Regulator, but may vary by project and Nations.

How will information sharing be accommodated by proponents for Indigenous Nations lacking capacity to participate?

We are mindful some Indigenous nations may not have capacity to participate. We encourage oil and gas proponents to support Indigenous nations with whom they are working and offer flexible timelines where possible.

How can Indigenous Knowledge be incorporated into the planning of a project?

Proponents' pre-engagement with First Nations will guide how Indigenous Knowledge is potentially incorporated into project planning. While proponents may be aware of certain pieces of Indigenous Knowledge through past conversations, First Nations are the holder of this knowledge, so proponents should work directly with them to determine the appropriate way to apply available Indigenous Knowledge to a specific project. If a First Nation does not agree to share Indigenous Knowledge or such knowledge is not available after reasonable efforts to work with local communities, the proponent is not required to incorporate that First Nation’s Indigenous Knowledge in the assessment. Proponents should document their efforts working with First Nations and their Indigenous Knowledge within their pre-engagement report.

Are separate documents required for pre-engagement, environmental and social and cultural reports?

No. The pre-engagement report is key to understanding the Indigenous Knowledge that was brought forward. Available Indigenous Knowledge should be incorporated into the environmental and social and cultural assessments (when and where available) and can be included in one report.

What should be included in the social and cultural effects assessments?

Social and cultural effects are a project’s impacts on people and on the ways in which people and communities interact with their social, cultural and biophysical surroundings. These types of effects can be directly attributable to a project or can arise indirectly from a project’s activities; they can also be driven by project-related changes in the natural or biophysical environment. Some specific social or cultural effects that may be associated with a processing facility could include, but are not limited to:

  • Loss of an area with specific cultural or recreational value through conversion to a facility site and/or loss of access.
  • Increased hunting or fishing pressure caused by new access leading to reduced wildlife populations.
  • Noise, light, vibration, or odours that affect adjacent lands valued by people.
  • Alteration (e.g., avoidance, displacement) of First Nations harvesting activities, such as hunting, fishing, gathering, and trapping and/or changes in availability and utility of preferred harvested species and occupation sites.
  • Alteration/removal of/increased access to archaeological/cultural heritage sites, sacred sites, trails and culturally/spiritually important sites and culturally modified trees.
  • Increased traffic that significantly affects other road users and/or nearby people.
  • Visual impacts that are likely to appreciably alter the character of the visual landscape as seen from viewpoints.

What is the expectation of the Regulator for the preliminary consequence assessment requirement?

The applicant should note that the Emergency Management Regulation requires the definition of hazard planning zones for all hazards. These planning zones are based on consequence assessments (section 7 of the Emergency Management Regulation) and must be shared with “a person who occupies land that is located within the emergency planning zone” (section 13 of the Emergency Management Regulation). At the application stage, an applicant must provide consequence assessments for the hazards associated with the proposed facility that are sufficiently conservative, and that are expected to be consistent with future hazard planning zones. Refer to CSA Z246.2 for further information, particularly Annex A.8, which includes details on Hazard Identification and Consequence Analysis with a reference to CCPS 2008 Guidelines for Hazard Evaluation Procedures.

How have cumulative effects been considered in the Guidance?

The consideration of cumulative effects is now included in the guidance, as it is recognized they are a critical element in assessment of impacts. Section of the guidance document, ‘Scope of the Environmental Effects Assessment Report’, includes a requirement for an assessment of cumulative effects to environmental values as part of the permit application process. The guidance states that this assessment should include an evaluation of current disturbances within proximal watersheds, and current conditions, using approaches consistent with the most current updated guidance at the time of application development. The Regulator notes this section of the guidance document is expected to continue to evolve as better information becomes known about considering cumulative effects.

What does the Guidance say about factors such as wastewater, atmospheric emissions and other hazards being incorporated into the environmental effects assessment report?

Regulator staff have added requirements for baseline and ongoing monitoring to the guidance document, as well as noting that potential impacts to water and air need to be evaluated and monitored relative to ambient provincial standards. Residual risk has also been added to the impact assessment table (in addition to mitigation).

How will baseline states be determined and what does ongoing monitoring mean?

The applicant will be required to determine, with appropriate assessments and Indigenous Knowledge obtained in the pre-engagement process, where monitoring is required, and at which phases of the lifecycle of the facility. For example, the guidance document contains technical guidance for perimeter groundwater monitoring, including establishing baseline groundwater conditions and ongoing monitoring throughout the life of the processing facility, until full site restoration is complete. Ongoing monitoring of representative indicator parameters is to be determined by a Qualified Professional.

What is the expectation of the Regulator for the quality assurance program verification report?

The Regulation, section 4(4)(c)(ii), defines the scope as verification that the permit holder will have processes and procedures ensuring that the facility will be constructed to the applicable requirements specifically in section 6 (management system) and 7 (engineering siting and design) of the OGPFR. This can be specified in the permit holders QA program verification. In summary, at the application stage, the requirement is to verify the applicant has an overarching quality assurance program in place to ensure the appropriate quality assurance and quality control measures are setup for the detailed engineering, procurement, fabrication, construction, and commissioning of the processing facility. The overarching or project quality assurance program should be documented and include an overview of the requirements for managing quality.

Are Piping & Instrumentation Diagrams (P & IDs) required for the permit application to be accepted?

No. Preliminary engineering design information and drawings (PFDs and preliminary plot plans) are required for the oil and gas processing facility permit application. If P & IDs are available, they can be included in the permit application and will assist in the Regulator’s engineering review process.

The Regulation refers to CSA Z767 in section 2(2)(k). Is this standard mandatory to follow? What is new in this standard that hasn’t been required for gas processing facilities in B.C. up to this point?

Yes, except for clause 7.4 in CSA Z767, the standard will be mandatory to follow for all new and operating oil and gas processing facilities in B.C. as of March 4, 2022. This standard includes the following examples of new requirements that were historically followed by many permit holders as industry best practices, but now are mandatory for all permit holders of processing facilities:

  • Maintaining up-to-date Process Safety information and documentation.
  • Process Safety hazard and risk assessment throughout a project and during operations.
  • Alarm and instrument management processes.
  • Pre-Startup-Safety-Reviews before starting up new or modified processes and equipment.
  • Continual improvement practices for Process Safety management.

How do we submit the details for modular units constructed outside of British Columbia?

The description and construction plan for the module are required, if the applicant intends to construct a modular unit outside B.C., and can be included in the project description and consist of a preliminary overview.

What does the modular unit verification report include? Does it have to be submitted to the Regulator?

The report must verify all modular units in the processing facility have been constructed and tested in accordance with the management system and prepared by a qualified professional or a third party acceptable to the Regulator. The report does not have to be submitted to the Regulator but must be made available upon request during facility construction, at start-up or at a future audit. The modular verification report should include all modular unit inspection and verification documentation, including those for pressure piping and pressure vessel fabrication.

Is the Regulator able to recommend more than the two days’ notice prior to construction or equipment on location that exists in the Regulation?

The time period in the Regulation itself is two days’ notice. Until such time as the timelines are extended in the Regulation, the Regulator has provided recommendations in the guidance to oil and gas proponents to provide more than two days’ notice to the Regulator and to Indigenous nations, where possible.

Individual nations can also request to receive notices during engagement with the proponent, or request they be added as permit conditions during consultation with the Regulator.

The Regulator will further consider this feedback when the regulation is next up for review.

Are there any new requirements as part of the pre-start-up inspection process of a newly constructed processing facility from the previous gas processing facilities pre-start-up inspection?

Yes. There is a new process that mirrors most of the previous pre-start-up inspection process. Under section 14 (pre-operation testing), the updated process requires submission to the Regulator of a schedule outlining when inspections and tests are to be conducted by the permit holder. The Regulator will respond within seven and 14 days identifying which inspections and tests are to be witnessed by the Regulator prior to the commencement of facility operations.

Is a perimeter groundwater monitoring program consideration required for existing gas processing plants as it is for new processing facilities?

The Regulation does not specifically require development of a groundwater monitoring program for newly proposed, existing or suspended processing facilities. However, the expectation is for permit holders of new processing facilities to verify their activities do not impact groundwater by developing and implementing a perimeter groundwater monitoring program. Permit holders of existing processing facilities will be expected to have qualified professionals evaluate the risks to groundwater to determine if they are required.

The requirement of the permit holder to submit a schedule of pre-operation facility inspections and tests to the Regulator, and the determination of tests needing to be witnessed potentially poses a risk to timelines. How will the Regulator address this risk?

The submission of the pre-operation testing schedule is understood to be a tentative timeline and is used to arrange the witnessing of the selected test. There will be communication between the construction manager and the Regulator inspector as to what test is desired to be witnessed and the actual date of the selected test.

Has the start-up process of a processing facility changed with the Regulation? Are there any new requirements?

Yes, the process has changed. While the general protocol and notification timeline has not changed, the permit holder must submit the following to the Regulator prior to commencing facility operations:

  • A notice stating they have implemented the management system,
  • A copy of the security management system referred to in section 6(2)(b) of the Regulation, and
  • A list, completed by a qualified professional as defined in the Regulation, of all safety critical devices at the processing facility.

What has changed with the requirements for section 23 (suspension) and section 24 (decommissioning) of a processing facility?

The new processing facility suspension requirements include the preparation, implementation and submission to the Regulator of a suspension plan prepared by a qualified professional. There are new decommissioning requirements based on the processing facility not resuming operations within two years after a suspension of operations begins. This includes the requirement to carry out a contaminated sites assessment, and have a qualified professional prepare a plan to remove facilities and equipment on the facility area and remediate and restore the site. A preliminary site investigation may be acceptable if the presence of site equipment and piping hinders the ability to complete a representative contaminated sites assessment. The plan must be submitted with a schedule of activities and approved by the Regulator before being implemented by the permit holder.

Does the management system referred to in Section 6 have to be submitted to the Regulator? Is a corporate plan acceptable versus a separate system for each processing facility?

The management system does not have to be submitted to the Regulator unless it is requested as part of an audit or review. A typical management system includes corporate level components and objectives along with the management of potential hazards throughout the lifecycle of each processing facility.

What are the expectations of the environmental management program component of the management system?

The environmental management program must detail the processes and procedures in place to minimize the adverse effect the processing facility could have on the environment over the facility’s lifecycle. Some of the environmental management program expectations include, but are not limited to:

  • Leak detection plan
  • Flaring management plan
  • Industrial wastewater and surface runoff control plan
  • Groundwater management plan
  • Wildlife management planning and operational measures
  • Soil monitoring plan

Are there any changes to requirements related to flaring at processing facilities?

The Regulation, section 21(2), includes a new requirement for flaring activities and related emissions that follows the EPA Method 22 protocol. During emergency/maintenance operations emissions are to be visible for no more than five minutes in any two-hour period, are not a material threat to life or health and do not cause off-lease odours or injury to vegetation or wildlife.

What changes are there for the submission of record drawings for processing facilities?

The requirements have changed from what the Drilling & Production Regulation has historically required for gas processing facilities. Record drawings must now be submitted within nine months after the permit holder begins to operate the processing facility. The record drawings must include piping and instrumentation diagrams, process flow diagrams, metering schematics and plot plans.

Is the permit holder required to submit the security management plan at start-up, as this document will potentially include confidential information?

Submission of the security management plan (SMP) will not be required at the start-up of the processing facility. A brief summary of the SMP will be acceptable, which addresses the confidentiality concerns.

How can Indigenous Nations be notified if operations are to be suspended?

We are aware the Regulation does not require proponents to notify the Regulator, or Indigenous nations if operations are going to be suspended. The Regulation states that after 12 months of becoming inactive, the permit holder must safely suspend the facility and submit a copy of the suspension plan prepared by a qualified professional to the Regulator. Regulator staff have added language to the guidance document recommending proponents notify local Indigenous nations before operations are suspended. As well, individual Nations can also request to receive notices during engagement with the proponent, or request they be added as permit conditions during consultation with the Regulator.

Where can I find other resources?

If you have further questions about the Regulation, please contact any of the following:

Engineering: James Gladysz, P.L.Eng.,
Permits: Adam Kamp,
Indigenous Relations initiatives: Kate Hewitt,
Regulatory Affairs: April Wynne-Chesniak,

Orphan Site Management Frequently Asked Questions

What happens when a permit holder becomes insolvent or cannot be located?

The Regulator may choose to designate these sites as “orphans”. The designation allows site clean-up and restoration work to be overseen by the Regulator. The work is paid for from the industry-funded Orphan Site Restoration Fund.

How many orphan sites is the Regulator responsible for?

Please visit ‘Resources’ on the Orphan Sites homepage for a list of current orphans and their restoration status.

What is the process for restoration work? What happens first and when?

The Regulator’s first priority is to ensure pipelines and other infrastructure are deactivated and left in a safe state, and high-priority wells are abandoned. We then work to prioritize large-scale area-based decommissioning programs. As wells are abandoned and equipment is removed from sites, we can focus on delivering restoration programs to return agricultural land and forested areas to an acceptable state.

How do you prioritize which sites are restored first?

The Regulator plans and executes work on orphan sites based on consideration of relevant factors, including safety, protection of the environment, local needs, and efficient use of equipment and other resources required to restore sites.

How long to return the land back to where it was before the oil and gas activity?

Restoration of orphan sites, including all decommissioning, soil replacement, and planting, may take 10 years. However, many sites may be completed much sooner.

How can you guarantee there will be enough money in the Orphan Site Reclamation Fund?

In April 2019 the Regulator implemented a levy to collect $15 million per year from industry to ensure the timely restoration of orphan sites. The Regulator tracks and reviews the levy to ensure that we can meet our timely goals for restoration. The Regulator has a comprehensive plan to ensure risks on orphan sites are prioritized for immediate attention, and once risks are addressed, we implement large, area-based decommissioning and restoration programs for timely closure.

Who at the Regulator can I contact if I have further questions related to orphan sites?

Please send email inquiries to, or call the main line at 250-794-5200 and ask to be transferred to a member of the Orphan Restoration Team.

I have one (or more) orphan site(s) on my property, what happens next?

The Regulator will communicate with affected land owners to outline the compensation processes and what to expect as we carry out the restoration of the site(s).

If a solvent operator acquires a well/site (located on my land) formerly owned by an insolvent operator, what happens next?

A land owner can expect communications from the new company. Authority for right of entry and rental payments for these sites is under the purview of the Surface Rights Board, and land owners are encouraged to contact the Board if they have not heard from the new company within a reasonable period of time.

Will I be able to plant crops on the site again, will the soil be safe? What about sites within the Agricultural Land Reserve (ALR)?

The Regulator’s Certificate of Restoration process ensures the environmental quality of soil and groundwater meets acceptable standards before soils are replaced and seeding occurs. We also implement requirements for soil quality and quantity for land in the ALR in accordance with an agreement with the Agricultural Land Regulator.

What do I do if I receive notification of outstanding property taxes on the oil and gas site?

Land owners are not responsible for property taxes that pertain to oil and gas infrastructure on their land. Land owners should not pay taxes that are the responsibility of oil and gas operators and should communicate the error to the issuer.

What if I cannot receive financing from the bank because there is a lien on my property?

If a lien has been placed on oil and gas infrastructure on a land owner’s property, it is not the responsibility of the land owner. Land owners should contact the Ministry of Energy, Mines and Low Carbon Innovation for further information.

After a site is designated an orphan will I continue to receive rental payments? And who will pay?

When a site has been designated an orphan and the land owner is no longer receiving rental payments from the previous permit holder under the surface lease agreement, the Regulator may, under section 46 of the Energy Resource Activities Act, provide compensation to a land owner that is owed rental payments for an orphan site.

For more information on compensation and how to apply, visit the Land Owners and Compensation webpage under "Land Owners" on the Orphan Sites homepage. If you have additional questions, you may wish to review the following FAQs.

Can I apply for outstanding rental back payments from an insolvent permit holder?

An application for compensation for outstanding rental payments will be considered, for the period before an orphan site was designated, if the land owner submits proof of a lease agreement and a Surface Rights Board Order for missed rental payments.

For more information on compensation and how to apply, visit the Land Owners and Compensation webpage under "Land Owners" on the Orphan Sites homepage.

What is the difference between what the Surface Rights Board (SRB) can do and what the Regulator can do with respect to compensation for overdue orphan site rental payments?

The SRB may make a payment order against a permit holder or former permit holder with interest (which may be enforced like a court order with collection options), and sometimes may administer a security fund to satisfy payment. The Regulator may make payment (without interest) under section 46 of ERAA from the Orphan Site Reclamation Fund administered by the Regulator.

If I choose to apply to the Surface Rights Board (SRB), will the Regulator also consider my application for compensation?

Yes. After issuing a payment order against a former permit holder, the SRB will forward your application to the Regulator for review. If payment is outstanding, the Regulator will determine whether compensation is payable under section 46 of ERAA

Is an application for compensation required every year?

Yes, if you choose to apply to the Surface Rights Board. If you choose to apply to the Regulator, an application is required once. On each anniversary of the surface lease, the Regulator will examine your application, and assess and determine your eligibility for further payment(s).

If I initially apply to the SRB, can I later opt for automatic assessment by the Regulator to determine my eligibility on an annual basis?

Yes, if you notify the Regulator.

What is the reason for the ‘Assignment of Overdue Payments’ and what do the last two clauses mean?

The Assignment transfers to the Regulator the right to seek payment from the former permit holder for the money you receive from the Orphan Site Reclamation Fund (the Fund). In other words, instead of you pursuing the former permit holder for that money, the Regulator can pursue the former permit holder for reimbursement of the money paid to you from the Fund. Any money recovered by the Regulator is returned to the Fund, where it can be used to restore orphan sites, provide land owner compensation under section 46, or support other purposes of the Fund. It remains your choice to pursue any other claims you may have against the former permit holder under the surface lease.

Clause 1: “Nothing in or arising from this Assignment shall in any way alter or affect any other rights or claims of the Assignor under the Surface Lease, which may be pursued by the Assignor at its sole discretion.”

The clause means that the land owner remains a party to the surface lease and maintains any legal rights or claims that exist under the surface lease, other than the right to pursue payment from the former permit holder for money you receive from the Orphan Site Reclamation Fund.

Clause 2: “This Assignment does not convey any duties or obligations whatsoever to the Regulator under or arising from the Surface Lease.”

The clause means that the Regulator is not taking on any responsibilities or obligations under the surface lease as a result of the Assignment. The clause does not mean that you are waiving any rights to apply to the Regulator for additional payment in the future, nor does it alter the Regulator’s objective to complete restoration of orphan sites.

Is an Assignment required for both applications to the Regulator and the Surface Rights Board (SRB)?

Yes. An Assignment is required for each annual submission to the SRB, or only once with your initial application to the Regulator. The Surface Rights Board version can be found at and the Regulator version can be found at here.

An orphaned company was a Working Interest Participant in one of our wells, will the Orphan Site Reclamation Fund (OSRF) contribute to its decommissioning and restoration?

In B.C., there is no regulatory mechanism for permit holders to claim the defunct working interest’s share of closure costs from the OSRF. We understand that there is a provision for this in Alberta legislation; however, there is no such provision here in B.C.

Our company was a Working Interest Participant (WIP) in a now orphaned oil and gas activity. Will the Orphan Site Reclamation Fund (OSRF) be seeking contribution from us for the decommissioning and restoration of the orphaned site? Is there the expectation that one of the remaining WIPs assume care and custody of the site?

Legislation does not currently contemplate WIP as person’s responsible, nor is a permit holder able to make claims to the OSRF for defunct WIPs. If a permit holder’s site does become orphaned, the OSRF has the ability to pay the costs associated with the decommissioning and restoration of the site. Persons responsible for orphan debts under ERAA may include the permit holder and/or PNG tenure holder.

We need to cross an orphan pipeline. What is the process with crossing orphaned segments, and do I need a crossing agreement?

The Orphan Site Reclamation Fund/Regulator does not enter into crossing or proximity agreements for orphaned pipelines and/or sites; but we do ask proponents that due diligence and care is taken to ensure the ongoing integrity of the line to be crossed. This includes following all industry regulations and practices when working around buried piping and infrastructure.

We ask for an outline of the work and any mitigation activities that will be completed during construction/access, noting if there is any surface disturbance to the orphan pipeline right-of-way expected. If so, we would be looking to hear how you plan to minimize the impact, i.e. use matting or ramps where crossing orphan pipelines, and your plan to restore any resulting disturbance. We would then advise if we had any concerns. Notifications can be sent to

Our company is preparing to hydraulically fracture a pad and are in the process of sending out offset notifications. There are orphan wells within our frac planning zone (FPZ). What information is required and who do we notify?

Please forward all notifications to Notifications, as per Section 9.2.2 of the Oil and Gas Activity Operations Manual, should include the estimated date of completion, the well permit number(s), profile, stimulated formation, and total vertical depth of the wells to be stimulated, and the orphan wells that fall within the FPZ. We will then advise if we have any concerns with respect to the orphan wells and outline any mitigation that may be required.

We have a site in a remote/difficult/costly to access area of B.C. There are orphaned sites in the same area. Would the Orphan Site Reclamation Fund (OSRF) consider going into this area at the same time to share access costs?

The OSRF is always interested in exploring possible collaborations with permit holders, particularly in remote/difficult/costly areas, and is open to discussion.

I am interested in possibly acquiring equipment that remains on an orphan site. Is the Orphan Site Restoration Fund (OSRF) interested in exploring such opportunities?

Yes, the OSRF is open to discussing opportunities for others to acquire equipment from orphan sites, please contact The Regulator prefers one of our approved contractors be utilized for the work (billed to the 'purchaser’); should you wish to use a contractor of your choosing we would require a supervisor from an approved OSRF vendor be present.

I can provide services. How can I get on your vendor list to provide these services to the Orphan Site Restoration Fund (OSRF)?

We periodically post a Request for Standing Offer through the Regulator’s procurement portal and on BC Bid to establish Standing Offers for services required by the OSRF.

If the services you offer fall under the direction of our prime contractors, it is at their discretion to seek the services of sub-contractors they may require.

What is the difference between a Standing Offer and a Contract?

Following a Request for Standing Offer, successful proponents will enter into a Standing Offer to provide services to the Orphan Site Reclamation Fund as required. The decision to use any Standing Offer will rest with the Regulator. A Standing Offer is not a contract. A contract is created only when a scope of work is awarded and the Regulator issues a Draw-Down of services under the Standing Offer. A General Service Agreement will be used to execute the Draw-Down of services.

If Standing Offer(s) have already been awarded, is there another way to become an approved vendor?

The Regulator will continue to accept additional proposals after a Request for Standing Offer has closed; however, such additional proposals will only be reviewed if and when necessary to add additional contractors to the Standing Offer. Subsequent submissions will be reviewed against the same criteria as was considered in the Request for Standing Offer. Successful contractor(s) who establish a Standing Offer for services with the Regulator may be selected for existing and future opportunities at the discretion of the Regulator.

How long is a Standing Offer valid for and is there an opportunity to revise costs?

It is anticipated that the term of a Standing Offer will be for one year with an option to renew for two additional one-year terms at the discretion of the Regulator. Pricing is to be firm for the duration of the standing offer term. Should the Regulator choose the renewal option, the Contractor(s) will be contacted prior to the renewal period to discuss any changes to the standing offer. Any renewal pricing submitted is subject to approval and will need to be firm for the renewal term.

Petrinex Frequently Asked Questions

1. What are the main changes to Regulator processes and systems?

Some Regulator business processes will be integrated into Petrinex. These process changes will impact eSubmission, KERMIT, AMS, Data Downloads and some paper-based application processes. Details are provided in the answers below within the Release Guide to Regulator System Changes.

2. How is eSubmission changing?

Section 2 of the Release Guide outlines changes to eSubmission. Updates will be made to the eSubmission User Guide to reflect all changes, effective November 5, 2018.

3. How is KERMIT changing?

Sections 3 of the Release Guide outlines changes facility management within KERMIT. Changes to BA identifiers within KERMIT are described in Section 4. Updates will be made to the Oil and Gas Activity Operations Manual to reflect all changes, effective November 5, 2018.

4. How is the application process changing?

There will be a minor change to the facility types included in the facility application process. The pipeline gathering facility type will be eliminated from the options within the Application Management System. Instead of using this pipeline gathering facility type to accommodate the flowing of wells to two or more different reporting facilities, operators will have the capability to set up special reporting batteries in Petrinex.

5. How does the process for setting up new companies change?

Section 4 of the Release Guide outlines changes to company administration. Currently, new companies are required to complete the New Company Application Process before the Regulator will accept any permit applications. Once Petrinex is implemented, the new company application process will be administered through Petrinex. Updates will be made to the Permit Administration and Operations Manual and the Oil and Gas Activity Application Manual to reflect these changes, effective November 5, 2018.

6. How does the Petrinex implementation impact permit transfers?

There will be no change to the transfer process at this time.

7. How do I get access to Petrinex?

Petrinex access will be available as of November 5, 2018 to operators who have completed the Business Associate Data Collection Form. For more information on this, see the Regulator’s Petrinex web page.

8. How do I get access to Regulator systems?

To access any Online System you need to have an account and one or more security roles for the permit holder you plan to act on behalf of. See Online Systems Accounts for guidance on how to get started.

9. Are there any regulatory changes resulting from the introduction of Petrinex?

Minor changes were made to regulations under the Oil and Gas Activities align reporting dates to Petrinex.

10. Will there be any training offered on the process and system changes summarized above?

The Regulator offered training on the new functionality integrated into eSubmission via webinar on October 10, 2018. A link to the training session and a copy of the Power Point Presentation are available on the Regulator’s Petrinex web page.

11. When will Regulator manuals and guidelines be updated to reflect these process and system changes?

The Regulator will publish updates to manuals and guidelines impacted as part of the monthly documentation update process. In the interim, all changes are documented within the Release Guide.

12. When do I switch from reporting well statuses via the BC-11 to reporting them in Petrinex?

All well status changes dated October 1, 2018 and onwards must be made in Petrinex. These changes can be made in Petrinex as of November 5. For status changes dated September 30, 2018 and earlier a BC-11 must be submitted prior to October 22, 2018.

13. When do I report a new Completion Event in eSubmission?

A completion event can be reported to the Regulator once completion work has commenced. The completion must be reported prior to reporting volumetrics. Please note that the reporting of a completion event is a separate process from the submission of a completion/workover report.

14. When do I use a ‘Gas Testing’ well status?

A gas testing status is valid only for period of well activity when gas flaring associated with well clean up and deliverability testing is occurring and there are no sales of marketable gas or by-products.

15. How do I amend a status before October 1, 2018?

Permit holders cannot amend well statuses effective prior to October 1, 2018. Please contact the Regulator via Online Services Support to request a status amendment.

16. When transitioning to a new status, what date should I use?

An active status must have a status date occurring on or before the date production commences (or recommences) in order to facilitate volumetric reporting. In order for the Regulator to assign the correct abandon zone date, a suspended status must have a status date occurring prior to any downhole abandonment operations. When a suspension date occurring after the operations is reported by a permit holder; the Regulator will be unable to assign the correct abandon zone date and will be forced to choose a date occurring after the suspension status date.

Pressure Piping Within Oil and Gas Facilities Frequently Asked Questions

Why were changes made to the Safety Standards Act in November 2016?

The changes to the Safety Standards Act introduced through Bill 13 were to clarify jurisdictional responsibilities in the areas of pressure piping and refrigeration systems. The changes are expected to result in more efficient oversight of oil and gas operations in B.C. and allow both the Regulator and Technical Safety BC to focus their efforts in those areas of responsibility. For more information, please see Industry Bulletin 2016-34 Safety Standards Amendment Act Resulting Regulatory Authority and Process Changes.

Is the Schedule A from the MOU between the Regulator and Technical Safety BC (formerly BCSA) from Sept. 14, 2009 still in effect?

MOU Schedule A from 2009 is no longer in effect, therefore none of its attachments are in effect. The current MOU is available online.

Do the changes to the Safety Standards Act in November 2016 affect facilities under National Energy Board (NEB) jurisdiction?

No, the changes only affect facilities regulated under the Oil and Gas Activities Act. If the facility is NEB regulated, the BC Energy Regulator has no regulatory involvement in the equipment, piping or components. For further information, please contact the NEB or Technical Safety BC directly.

How does the Regulator review applications from a safety perspective?

Application design review is the first stage in our regulatory lifecycle approach to managing risks to public safety and the environment. The Regulator reviews facility applications as an integrated system of singular components required to perform safely as a whole network. By focusing on where and how components interface within the system, the Regulator can evaluate and assess the interaction of the elements with an eye for risk, reliability and safety.

How does the Regulator ensure facility designs comply with regulations, codes and standards?

The Regulator utilizes a professional reliance model in some specific areas of its regulation of oil and gas activities. Engineering designs must be signed and sealed for use in B.C. by a member of Engineers & Geoscientists BC (formerly APEGBC). The requirements apply to the design, construction, operations/maintenance and decommissioning stages of projects. This professional reliance model is supplemented at the application stage by a design review process performed by Regulator professional staff or third party subject matter experts. Additionally, targeted field inspections are undertaken during the construction, commissioning, operations, and decommissioning phases.

How do applicants meet professional reliance requirements if designing outside of B.C.?

If an applicant intends to design all or a portion of a facility outside of B.C., they should refer to the Engineers & Geoscientists Quality Management Guidelines - Use of Seal, section Appendix D of the LNG Facility Application and Operations Manual provides further guidance on how to meet professional reliance requirements to the Regulator’s satisfaction and is consistent with the Engineering & Geoscientists Quality Management Guidelines.

It would seem that in B.C., design registration and Canadian Registration Numbers (CRN) for pressure piping components (fittings) used in oil and gas activities are no longer required? Is this correct?

Yes this is correct, the legislation refers directly to ASME B31.3 as an acceptable design code (not CSA B51), therefore design registration is not required for process pressure piping and fittings. In cases where CSA B51 is the design standard, design registration is required. A proponent may still choose to register for CRNs in any circumstance and can do this through Technical Safety BC.

Should pressure piping system design registration packages for oil and gas activities (other than power plant piping) be submitted to Technical Safety BC?

There is no requirement to submit these packages to Technical Safety BC, except in instances where there is a design requirement to follow CSA B51. Proponents may still choose to register for Canadian Registration Numbers (CRN) for any reason and can do this through Technical Safety BC.

Will documentation typically included in a design registration application (Mechanical Line List [on-skid + off-skid piping], P&IDs, PSV list, pipe material specs, stress analysis calculations, etc.) be required by the Regulator?

Prior to start-up following installation of the piping, the permit holder must have all this information available. The signed and sealed P&IDs must be submitted to the Regulator following installation of the piping. The Regulator may choose to audit the rest of the documentation.

What action should a permit holder take if a design is currently registered?

If a design is currently registered, it is up to the permit holder whether to maintain the registration or cancel it. If they choose to keep it registered, design registrations for Regulator-regulated elements will be reviewed and administered by Technical Safety BC. In these cases, compliance with the design registration requirements will fall to the Regulator. This would be in addition to the Regulator requirements.

Can you define the Regulator's welder qualification process for both ASME and CSA projects?

The welder qualification shall be in accordance with the requirements in the code of construction (e.g. ASME B31.3, Section 328.2 and CSA Z662 Clause 7.8).

What additional welder registration or certification requirements does the Regulator have above the requirements in the code of construction?

The Regulator has no extra requirements for welders above what is required by the code of construction.

Will the Regulator administer the registration if the code of construction requires registration of the welder or weld procedure?

No. If the code of construction requires registration in the province where the welding is to be performed (e.g. CSA B51), Technical Safety BC will administer the registration.

Will the Regulator authorize test facilities to perform welder qualifications?

The Regulator does not authorize test facilities.

Is the Regulator requesting that Technical Safety BC form 1329 or 1330 Declarations of Construction be available at time of inspection for facilities to obtain operating permits or Leave To Open (LTOs)?

Forms 1329 and 1330 were created by Technical Safety BC to satisfy the requirement to submit manufacturer’s data reports under CSA B51. The Regulator would not require submission of these forms if design registration was pursued by a proponent. ASME B31.3 requires inspection by the owner’s inspector (or the inspector’s delegates) and therefore, if the Regulator chooses to verify the satisfactory completion of the required examinations and testing, the Regulator would request a copy of the inspector’s verification report indicating compliance to the code and the engineering design.

Are there specific qualifications for site construction inspectors/supervisors overseeing construction at an oil and gas activity?

The Regulator requires permit holders ensure all workers including inspectors and supervisors are competent (i.e. qualified, trained and experienced to perform the required duties). Note that for pressure piping designed to ASME B31.3, the standard includes minimum qualifications for inspectors.

Can piping systems be designed to CSA Z662 rather than ASME B31.3?

Section 78(3) of the Drilling and Production Regulation states piping at facilities must be designed, constructed and operated in accordance with CSA Z662 or ASME B31.3. The only exception is for piping at gas processing plants and LNG facilities. All code breaks must be shown on the as-built drawings.

Does Technical Safety BC Form 1526 need to be completed for changes to burner management systems and associated fuel gas trains that are under the Regulator's jurisdiction?

The Regulator does not require completion and submission of this form in order to complete the upgrades. However, the required information listed in the form must be available and provided to the Regulator if requested.

Does the installation of fuel gas trains that meet the CSA B149.3 code require inspection and certification by a third party?

For fuel gas trains where the CSA B149.3 code is followed in the design of gas fired appliances (such as line heaters, tank heaters, glycol and amine reboilers, etc.), the as-built or record drawings for these facilities must clearly state they were designed and constructed in compliance with the requirements in CSA B149.3. It is a regulatory requirement that these drawings are stamped and signed by a professional engineer registered in B.C. The Regulator does not require certification by a third party.

For pressure piping and refrigeration systems at a facility permitted under the Regulator's jurisdiction, is a permit renewal required if the systems were previously permitted/authorized by Technical Safety BC?

No, the Regulator does not require permit renewal to operate pressure piping and refrigeration systems at a facility that was permitted under Oil and Gas Activities Act (OGAA).

Water Management Frequently Asked Questions

Why is water used for hydraulic fracturing?

Water is used for various stages of unconventional gas development. It is used during geophysical exploration, for washing equipment, to freeze winter ice roads, for dust control, for drilling wells, as part of the hydraulic fracturing injection process and for hydrostatic testing of pipelines.

During the hydraulic fracturing stage of unconventional gas development, water is mixed with sand and chemicals and pumped down the wellbore. Fractures are then created in the target formation, allowing natural gas to flow up the wellbore.

How is water allocated for oil and gas activities?

The BC Energy Regulator (BCER) has delegated authority to issue water licences under Section 9 and short-term water use approvals under Section 10 of the Water Sustainability Act. We consider a number of key points when reviewing water use applications, such as runoff levels in rivers, groundwater aquifer productivity, other water users and ecological values. Community and ecological needs must be able to be sustained before a water licence or approval is issued and conditions may be attached to the licence or approval. The BCER is a proactive regulator with the authority to intervene when necessary.

How much water is used?

The BCER tracks all water used for hydraulic fracturing and other oil and gas purposes through regulatory reporting requirements. Water use for oil and gas purposes varies significantly from month to month and year to year depending on a variety of factors including industry growth, well completion and production aspects, seasonal factors, water restrictions, or other factors. In 2018, approximately 3.28 million m3 of surface water and groundwater was used for oil and gas activities. On a per well basis, the volume of water used for hydraulic fracturing ranges from 10,000 to 70,000 m3 depending on the targeted formation and the number of fracture stimulations.

In most river basins, the total approved surface water use is a fraction of the mean annual surface runoff. For the majority of basins, approved water use corresponds to less than fraction of a per cent of mean annual runoff.

How is groundwater quality protected?

Provincial laws outline how the oil and gas industry must ensure water resources, including groundwater, are protected from contamination throughout the lifecycle of an oil and gas activity (from application through restoration) Regulatory provisions for groundwater protection include:

  1. Prevention requirements (e.g., setbacks and location restrictions, engineering specifications and standards for all wells, pipelines, and facilities, operational requirements, testing and emergency preparedness requirements)
  2. Monitoring requirements (e.g., operational safety and environmental monitoring and reporting)
  3. Mitigation requirements (e.g., emergency response, site remediation and reclamation)

In addition to legislation, special conditions may be prescribed in permits for energy activities, to address site-specific issues or concerns.

As an example for engineering requirements for oil and gas wells, pressure-tested steel casings are cemented in place to prevent deeper underground fluids (e.g., saline water, oil, gas) and hydraulic fracturing fluids from migrating into freshwater aquifers. At the time of well decommissioning, requirements include isolating porous intervals using cement, and cutting and capping the well below ground prior to site restoration.

What happens to produced water?

Produced water, saline water originating from deep formations which comes to the surface with natural gas and oil production, is injected into approved disposal wells. If this water is produced from an oil pool under waterflood recovery, the water is re-injected back into the same pool.

Produced water includes the flow-back of water-based hydraulic fracture fluid. Currently, about 50 per cent of this produced water is reused in hydraulic fracturing operations. This produced water may be stored temporarily before re-use but is eventually injected into approved disposal service wells, both which are subject to strict regulations.

What is being done to ensure water supplies are conserved?

To ensure river and lake levels are conserved for community water supplies and fish and aquatic resources are not impacted, the BCER can and does issue suspensions of short-term water use by the energy industry during drought conditions. Water licences contain specific conditions to limit withdrawals during periods of low flow. All groundwater licence applications are reviewed for potential hydraulic connection with surface water.

Approximately, 65 per cent of water used for oil and gas activities comes from surface water. The remaining 35 per cent comes from recycled water such as flowback fluids from operations or deep groundwater aquifers located more than 800m below the surface. Some water comes from shallow groundwater aquifers typically shallower than 300 m below ground.

On average, there is an abundance of water in northeast B.C. but it needs to be managed carefully, for example the BCER halts industry water withdrawals during periods of seasonal low flow and drought. The BCER has also developed NEWT to support decision makers by providing average water availability and water approval data, for streams and lakes.

Where can I find more data or information?

Fact Sheets defining water used in natural gas activities can be found here.

We publish water allocation and use data here. For each basin, the mean annual runoff is listed.

The Northeast Water Tool (NEWT) provides information for decision makers on average streamflow conditions and water authorized for use.

The Water Portal provides a range of water-related data and information.

The Groundwater Review Assistant (GWRA) compiles available groundwater data to assist in conducting hydrogeological reviews for groundwater licence applications or to support review for a variety of groundwater protection aspects.

Links to all water tools are available here:

If you have further questions about water use for oil and gas activities in B.C. or the Regulator in general, please email

Wells Frequently Asked Questions

How far can well point locations move before an amendment is required?

An amendment is not required when relocating the well head location within the permitted wellpad. After drilling, final well head UTM coordinates must be reported in the eSubmission portal using the As-Drill Survey Plan process. If the final UTM coordinates result in the well head being located in a different NTS or DLS legal location than what was originally permitted, the legal location and well name will be updated to reflect the as-drilled NTS or DLS legal location using the next available exception code. Well names will not automatically be renamed to be in sequential order and exception codes will not be re-assigned according to drilling sequence.

Where do I find information for how far a wellsite has to be set back from a residence?

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

Where can I find information on equipment spacing?

General guidance on equipment spacing is included in the Oil and Gas Operations Manual (Table 9E: Recommended Spacing Distances). Sections 45, 47 and 48 of the Drilling and Production Regulation includes spacing requirements that must be followed.

Do we have to do an application for a tower with a scada device on it now with OGAA in effect?

No application is required if the tower is being installed on OGC approved land.

Can quantifying venting/flaring at wellsites be done by estimate? In general, most wellsites will only have maintenance flare stacks on site and won't be flaring at all during normal operation.

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

Are flaring activities included in the consultation/notification requirement?

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.

I want to abandon a well. Is this done as per AER Guide 20 and will I need a cement plug at surface?

The Regulator has published a set of well decommissioning guidelines to meet the regulatory requirements under the Drilling and Production Regulation. Surface cement plugs are not required under the guidelines.

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