Skip to main content

On October 1, 2021, the Canadian Standards Association (CSA) released the draft 2022 edition of CSAZ276 Liquefied natural gas (LNG) – Production, storage, and handling for public review. The public review and comment period will close November 30, 2021.

For further information, please refer to the draft review section of the CSA website.

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 Commission’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 Commission 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 Commission 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 Commission’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 Commission 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 Commission 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 Commission’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 Oil and Gas Commission?

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

Will the BC Oil and Gas Commission 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 Commission proceed to a decision. The Commission 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 Commission 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 Commission 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 Commission databases, the land identifier (LAND_ID) attribute must me left empty; this will be the case for all land authorizations approved by the Commission prior to ePass. In this situation Commission 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 Commission, 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 Commissions 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 Commission; 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 Commission will replace Master Licenses to Cut twenty-three months prior to the expiry of the current MLTC. The Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 consultated 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 Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 Commission’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 Commission. The requirements for revisions and are set out in s. 13 and s.14 of the RCNR.

The Commission’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.

INDB 2019-13, dated June 14, 2019, state that the changes to the interim measures are effective immediately. What about applications currently in review?

The Blueberry River First Nations Application Assessment Form will be required to be submitted with applications within Areas 1, 2, and 3 effective June 17, 2019. Applications received prior to June 17, 2019 within Areas 1, 2, and 3 and are under review by the Commission are not subject to the new form. Click here to see INDB 2019-13.

Is the Blueberry River First Nations Application Assessment Form mandatory for all applications?

The form is mandatory for those applications that fall within the OGC Operational Zones: North or Central. Please ensure the form is completed and included as a miscellaneous attachment with your application.

My application falls outside of the North and Central zones. Is the Blueberry River First Nations Application Assessment Form required?

No, the form is not required for applications that are not within the North or Central Zones.

Do you have a metric or definition for a “timely offset restoration”?

This is currently under development.

Have Areas 1, 2, and 3 changed?

No, Areas 1, 2, and 3, as defined in INDB 2018-15 remain the same.

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.

ePayment Frequently Asked Questions

What is ePayment?

ePayment is the Commission'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 Commission 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 Commission does not accept payment by credit card.

What is required to setup an ePayment account?

In order to setup an ePayment account the Commission 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 Commission.

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 Commission 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 Commission sign indemnity agreements?

No, the Commission does not sign indemnity agreements.

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

Please contact a finance representative at the Commission 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 Commissions 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 Commission 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?

Commission 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 Commission’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 Commission automatically debit the accounts for unpaid invoices?

No, the Commission cannot debit bank accounts. Users with the ePay Payer role initiate the payment. The Commission 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.

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 Commission is actively engaged in the Regional Strategic Environmental Initiative (RSEA) to listen to First Nation concerns regarding cumulative effects in northeast BC. The Commission is also engaging with First Nations and the Aboriginal Liaison Program in field assessments and validation processes (under the FREP program). The Commission 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 Commission 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 Commission validate ABA status?

The Commission 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 Commission 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 Commission 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 Commission’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 Commission strives to see no new disturbance where the ABA Status is enhanced management or regulatory policy. When activity is unavoidable in these areas, the Commission 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 Commission considers Area-based Analysis (ABA) in reviewing applications under the Land and Habitat Review. Delegated and statutory decision makers of the Commission 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.

eSubmission Frequently Asked Questions

Will I be able to track my submissions in the eSubmission portal?

Yes, there is a submission log application within eSubmission that will allow you to track all submissions made to the Commission. A log is in each application and then a detailed submission log that allows you to both track, and download, your submissions is also available. For well data submissions, the DCP Admin role is required to access to the detailed submission log. More details on permissions can be found here.

Where do I submit questions that I might have about eSubmission? What if I have questions specifically about well data submissions?

General questions can be submitted to Questions specific to well data submissions can be submitted to

I have submitted an electronic report. Do I need to send in a paper (hard) copy too?

No, submissions received in electronic format do not require a duplicate paper (hard) copy submission. For more information on electronic data types, please refer to the eSubmission Portal User Guide.

How should I submit LAS logs?

LAS logs should be submitted using the LAS 3.0 file structure standard. The LAS 3.0 structure standard document can be found here. For additional information, please reference the Well Data Submission Requirements Manual.

Where can I find a list of the file types and naming conventions?

All file types and naming conventions are listed in Well Data Submission Requirements Manual.

How do I access the data found in the newly released eLibrary?

Please make your request using the Well Data Request Form and you will be given a unique username and password to access the eLibrary.

Will I be supplied with a template for submitting Water Use withdrawal volumes by the Commission?

Users are required to generate and download templates in .xml format directly from eSubmission. One or many Water Use Numbers can be included in a template. Once a user has generated a template, they can enter the volumes for the month(s) they are reporting for directly in the template, save the file according to the required file naming convention, and upload to eSubmission.

Do I have to download a new template each time I want to make a submission?

No. Users can download a template following permit approval, make edits to, and submit the same file at the end of each quarterly submission period. However, users must ensure the file name is updated each time a submission is made so it adheres to the required file naming convention. Duplicate file names are not acceptable. If a user chooses to generate a template for each submission they make, the template will contain any volumes previously submitted to the Commission. Previously submitted volumes will not be overwritten.

How do I open an .xml file?

To work with an .xml files users will need to have an .xml editing program installed on their machine. The Commission recommends the free-of-charge Notepad++ program.

I downloaded an .xml editor but my .xml file doesn’t open in the editor.

Once an .xml editing program has been installed, users need to set it as the default program for editing .xml files. In File Explorer, navigate to an .xml file, right-click and choose to open with a default program, and select the installed .xml editing program of your choice.

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.

KERMIT Frequently Asked Questions

What is KERMIT?

KERMIT (Knowledge, Enterprise, Resource, Management, Information, and Technology) is the BC Oil and Gas Commissions database application that provides industry with an electronic submission process for pipelines and facilities.

Why do I need to use KERMIT?

KERMIT provides the functionality to:

  • Submit Pipeline and Facility Construction Starts, Pressure Tests, Leave-To-Open's or As-builts
  • Submit Pipeline and Facility Notices of Intent
  • Search Pipeline Projects and Facilities
  • Manage user account security

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 Commission 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 Oil and Gas Commission.
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 Commission 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 Commission 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 Commission. 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 Commission 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 Commission.

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 Commission 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 Commission
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 Commission database.

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

The Commission 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 Commission 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 Commission has continuously engaged with stakeholders in the update of the liability model and the development of the Permittee Capability Assessment. The Commission 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 Commission’s website here. Ratios are calculated and updated daily.

The Commission 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.

Orphan Site Management Frequently Asked Questions

How do I apply for compensation for overdue rental payments under a surface lease agreement when a site is designated as an orphan?

Please review the document ‘How to Apply for Compensation’ at If you have additional questions, you may wish to review the following FAQs.

What is the difference between what the Surface Rights Board can do and what the Commission can do with respect to compensation for overdue rental payments in relation to an orphan site?

The Surface Rights Board (SRB) may make a payment order against a 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 Commission may make payment under section 46 of OGAA from the Orphan Site Reclamation Fund administered by the Commission.

If I choose to apply to the Surface Rights Board, will the Commission 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 Commission for review. If payment is outstanding, the Commission will determine whether compensation is payable under section 46 of OGAA.

Is an application for compensation required every year?

Yes, if you choose to apply to the SRB. If you choose to apply to the Commission, an application is required once. On each anniversary of the surface lease, the Commission 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 Commission to determine my eligibility on an annual basis?

Yes, if you notify the Commission.

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

The Assignment transfers to the Commission 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 Commission can pursue the former permit holder for reimbursement of the money paid to you from the Fund. Any money recovered by the Commission 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 Commission under or arising from the Surface Lease.”

The clause means that the Commission 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 Commission for additional payment in the future, nor does it alter the Commission’s objective to complete restoration of orphan sites

Is an Assignment required for both applications to the Commission and the SRB?

Yes. An Assignment is required for each annual submission to the SRB, or once with your initial application to the Commission (the SRB version is found on its website, the Commission version on its website).

I previously submitted an application for compensation to the Commission/SRB, and a Dec. 27, 2017 Commission letter states I don’t have to submit an application to the Commission again. However, I’ve never submitted an Assignment – will one be required?

Yes. The Commission will contact you on or near your next surface lease anniversary with respect to completion of an Assignment, unless you notify us that you are applying to the SRB. If you are not applying to the SRB, an Assignment will be required only once. If you choose to apply to the SRB, an Assignment will be required on an annual basis.

Who at the Commission can I contact if I have further questions related to compensation?

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

Petrinex Frequently Asked Questions

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

Some Commission 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 Commission 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 Commission 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 Commission’s Petrinex web page.

8. How do I get access to Commission 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 Commission 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 Commission’s Petrinex web page.

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

The Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 Commission 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 Oil and Gas Commission 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 Commission 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 Commission 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 Commission can evaluate and assess the interaction of the elements with an eye for risk, reliability and safety.

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

The Commission 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 Commission 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 Commission’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 Commission?

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 Commission following installation of the piping. The Commission 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 Commission-regulated elements will be reviewed and administered by Technical Safety BC. In these cases, compliance with the design registration requirements will fall to the Commission. This would be in addition to the Commission requirements.

Can you define the Commission'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 Commission have above the requirements in the code of construction?

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

Will the Commission 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 Commission authorize test facilities to perform welder qualifications?

The Commission does not authorize test facilities.

Is the Commission 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 Commission 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 Commission chooses to verify the satisfactory completion of the required examinations and testing, the Commission 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 Commission 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 Commission's jurisdiction?

The Commission 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 Commission 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 Commission does not require certification by a third party.

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

No, the Commission 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 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 Oil and Gas Commission (Commission) has delegated authority to issue water licences under Section 9 and short-term water use approvals under Section 10 of the Water Sustainability Act. The Commission considers 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 Commission is a proactive regulator with the authority to intervene when necessary.

How much water is used?

The Commission 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 0.2 per cent of mean annual runoff. Further, the amount of actual water used is typically less than the amount that is approved (e.g.,8.6% of approved water was actually used in 2018 due to a variety of factors).

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 Oil and Gas 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 Commission can and does issue suspensions of short-term water use by the oil and gas 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 Commission has halted industry water withdrawals during periods of seasonal low flow and drought in 2010, 2012, 2014, 2017, 2018 and 2019. The Commission 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.

The Commission publishes water use data via its Water Information page here. For each basin, the mean annual runoff are listed. A list of current Section 9 licences and Section 10 approvals is also available in the Water Reports.

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 Commission in general, please email

Wells Frequently Asked Questions

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

A well permit amendment is required when there is a change to the surface wellhead coordinates that results in a change to the legal surface location (NTS or DLS coordinates). For example, if the well is located in a boundary and a proposed change causes the legal surface location to change from 1-3 to 3-3. An amendment is not required when changing the wellhead location if there is no change to the wellhead surface location (NTS or DLS coordinates). However, if the wellhead location changes where an amendment is not required, the new well center coordinates must be submitted through eSubmission in the Drilling Section, Summary Report. The permitted well coordinates can then be changed to the new wellhead location.

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?

Guidelines for abandonments during drilling operations are found in the Drilling section of the Oil and Gas Activity Operations Manual. Guidelines for cased-well abandonments are found in the Completions, Maintenance and Abandonment section of the Oil and Gas Activity Operations Manual. Cased-well abandonments conducted in accordance with AER Directive 20 meet the intent of the regulatory requirements for well abandonments in B.C. A cement plug at surface is not required.

Need to troubleshoot?

For assistance with online systems, please contact us for help.

Online Systems Support

Website Feedback