Frequently Asked Questions

Where do I find the "Water Act Application Manual"?

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

The Commission's forms and manuals discuss "Areas Established by Order under the Oil & Gas Activities Act." Where do I find the above information? It is requested on the forms but I don't know where to look or find this data.

Orders established by the Ministry of the Environment for Wildlife Habitat Areas, Ungulate Winter Ranges, Fisheries Sensitive Watersheds, and Temperature Sensitive Streams, which continued those designations made under the Forest and Range Practices Act (FRPA) at the time that the EPMR came into effect (October 4th, 2010), were approved by the Deputy Ministry of Forests, Lands and Natural Resource Operations on August 18th, 2011.  All subsequent areas established by order will be legal under OGAA and the EPMR at the time of designation, and will be established spatially in the province’s Land Resource Data Warehouse.

Once an area has been legally established by Minister’s Order, it brings into effect “government’s environmental objective” for that area.  In accordance with section 25 (1) of OGAA, the Oil and Gas Commission must consider government’s environmental objectives for the species associated with the designated area.

Can we classify wetlands base solely on area ?

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

Are the visual quality objectives, as defined under FRPA, applicable to OGAA applications?

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

Are minimum construction setbacks no longer required for beaver ponds and oxbow lakes under the EMPR? Also, under the Water Regulation (Water Act) and the Wildlife Act, there are provisions to protect wildife and wildlife habitat; and the removal of this setback requirement, in my opinion, may result in operators causing harm or harassment unknowingly and violation of one or both of these Acts.

As below, the previously required setbacks are no longer outlined in the Regulation. This is not an error. Operators must still ensure however that environmental objectives set out in the Regulation are met. Furthermore, operators must be aware of other acts that affect their operations. Other acts may include but are not limited to the Water Act, Wildlife Act and the Species at Risk Act. Section 26 of the Environmental Protection Management Regulation (Regulation), Wildlife Habitat Features Identified states:

  1.  The minister responsible for administering the Wildlife Act, by order, may identify any or all of the following as a wildlife habitat feature:

(a) a fisheries sensitive feature;

(b) a marine sensitive feature;

(c) a significant mineral lick or wallow; (

d) a nest of

(i) a bald eagle,

(ii) an osprey,

(iii) a great blue heron, or

(iv) a category of species at risk that is limited to birds;

(e) any other localized feature that the minister responsible for the Wildlife Act considers to be a wildlife habitat feature.

  1. Identification of a wildlife habitat feature under subsection (1) may be by category or type and may be restricted to a specified geographic location. In addition, Section 6.9 of the Environmental Protection and Management Guidebook (Guidebook) Wildlife Construction Setbacks states: The following are the minimum suggested construction setbacks for each identified habitat feature: • Trumpeter Swan Nest – 200 meters; • Other nesting sites (i.e.: Osprey stick nest, sandhill crane ground nests) – 100 meters; • Mineral licks – 100 meters; • Bear dens (applies to winter construction only) – 50 meters; In some cases, additional setbacks may be required due to lack of topographical relief, sparse vegetation density, extensive use of habitat, and other special considerations. Where the minimum suggested construction setbacks are not being maintained, proponents are expected to submit to the Commission, as part of the oil and gas activity application, a rationale for the activity placement in proximity to the habitat feature and demonstrate how the integrity of the feature will be protected through mitigation. The Water Act, Wildlife Act and any other acts and regulations that may affect operations must be adhered to by any operator.
Is consultation/notification required for roads within a road allowance? Also, are we required to notify trappers/guides for these areas even though they aren't "technically" crown land

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

• NEWT can be accessed via  the following link

Below is a definition for each tool within the NEWT application.

  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.
  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.

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.

What regulatory limits there are there for NOx emissions (at a compressor site, gas plants etc.) in BC? Does OGAA/OGC regulate air emissions, other than the targets mentioned in the Flaring and Venting guideline?

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

What are the requirements for re-licensing a facility? Do we have to re-notify the landowners and re-submit a BC-20 Application with all the supporting documentation? Are there any additional requirements?

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

Under section 'Flaring and Venting' you require the venting rate. My question is do you require the venting rate for the new installations or do you require the venting rate for the entire site including what is already exisiting

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

Is there any equipment/equipment combination that would not require a permit?

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

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

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

If metering exists, is facility permit application required?

Generally all metering requires a permit.

Describe the current regulatory process for a well linkage change using the new Schedule 1 form that has replaced the BC-21?

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

Can quantifying venting/flaring at wellsites be done by estimate?

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

"Facility application Question #28: Will a method to recover low pressure vapours be implemented? For a facility handling H2S, how should this question be answered if the venting gas is being sweetened (scrubbed of H2S) but not recovered?

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

With the new NOI process, no BC-20 and/or BC-21 are required. Do companies then complete an amendment to the facility permit to apply a facility linkage to the new wellsites and to provide requirements such as P&IDs and plot plans?

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

What is the typical turn around on New Permit Holder applications?

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

How do I apply for a Frac-Sand Storage Site?

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

Are both temporary and permanent campsites to be completed on the Crown Land Application Form?

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

Written Report Cover Sheet: Is this form only to be filled out and signed by the land agent responsible for the consultation and notification, or can it be filled out and signed by the representative of the applicant who is submitting the facility permit (in this case the engineering firm who has only received the consultation information)?

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

When completing the Notification and Consultation line list for a particular company, do you have to list that company's projects on the line list that are within the notification and consultation radii as well?

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

Map requirements: In the manual it provides option sizes for map as 1:2500 or 1:5000. Is this just a recommendation? May we send out maps that show all info required but are at 1:20000 or 1:50000?

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

Legal description / 911 address of the C&N Linelist; Is it acceptable to enter "overlapped tenure" in this area instead of each of the lands affected by the tenure holder?

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

Landowner notification process 15 day waiting period; Does this include Woodlot Permit holders, and Ag Leases?

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

Is there an email address at the Commission that stakeholders can email their completed form to?

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

How do I apply for a common remote sump on private land?

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

Are consultation and notifications required for a pipeline replacement "in-kind?"

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

Is there an updated version of the Oil and Gas Handbook?

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

Have there been any changes to seismic procedures regarding parks & protected areas?

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

Has the requirement for a Geophysical Number been removed?

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

Cheques are payable to the "Oil and Gas Commission"

Cheques are payable to the "Oil and Gas Commission"

If we have a permitted wellsite and want to include equipment, is that equipment considered a facility?

The equipment would be either an oil facility or a non oil and gas facility; however, note that applications for these facilities on land that is already the subject of a permit (in this case a well permit) do not attract application fees. If, however, the wellsite includes equipment in the nature of compressors, dehydrators or gas processing plants, there is an application fee.

If the product going through a facility is natural gas, does that make it a natural gas facility?

No. The only facilities classified as natural gas facilities are compressors, dehydrators, and gas processing plants. If the product is natural gas, and the facility is not one of these three, it is a “non oil and gas facility”.

Is there a copy of the Fee, Levy and Security Regulation (Regulation) available online?

Yes. A copy is available on the Commission website under the ‘Legislation’ tab at Industry Bulletin 2014-02 distributed on Jan. 20, 2014 describes the changes that took place on the effective date of the Regulation (Feb. 6, 2014).

If I have multiple amendment applications underway and receive an amendment fee invoice, will I know which amendment I am being billed for?

Yes. A unique identifier will be applied to each amendment invoice to coordinate invoice payments.

Do I need to determine if my permit amendment application is minor or major in order to submit the proper fee with my amendment application?

At this time, amendment fees are not required when submitting a minor or major amendment application. The fee will be determined after the permit amendment application is received at the Commission. Once the decision-maker confirms whether the permit amendment is minor or major, the correct fee is then calculated and an invoice will be generated and mailed to the applicant.

I have two small access roads going to a borrow pit off the new well access road. Each is 10m x 15m. Do these two small roads going to the ancillary site have to be listed separately on the well application – under roads (main access road and ancillary site access roads)? Under ancillary sites? Or just be kept in the total with the new well access. If I have 2 borrow pits along the access road and one that clearly belongs with the wellsite. Under ancillary sites on permit application can it be the cumulative total of all borrow pits on plan or do they need to be area for borrow pits along access road and area for borrow pits associated with well site.

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

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

Typically, no. Only those that had an LMR less than 1.0 at the initial review at the inception of the LMR program in November 2011 were grandfathered into the phased payment schedule. New to BC operators who are drilling or purchasing their first wells, and those operators whose LMR falls below 1.0 as a result of a transfer or during a monthly review, are required to bring their rating to 1.0 in a single security installment.

The letter of credit beneficiary and cheques are payable to, BC Oil and Gas Commission.
Security deposits are to be couriered to:
BC Oil and Gas Commission
#300, 398 Harbour Rd
Victoria, BC  V9A 0B7
Attn: Finance

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.

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.

Security will be returned for one of two reasons.

  1. The Commission will consider, upon request by an operator, the return of a security deposit when a non security-adjusted LMR greater than 1.0 has been maintained for the most recent six or more consecutive months.
  2. Security will be automatically returned when an operator no longer holds any permits in BC.

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.

The OGC currently funds orphan well abandonments with a tax on production ($.06/m3 oil and $.03/e3m3 gas). One option used in other jurisdictions is through a fee based on a company’s liabilities as a fraction of industry liabilities.
The existing production-based Orphan Levy has been enacted in legislation. The Commission has no current plans to seek a change in legislation.

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.

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.

The Commission may at any time request a current ‘Permit Holder Netback Calculation’ form from disposers and processors to calculate the industry average netback for each non-producer category. An industry average netback can stay in effect for up to three years after its implementation; the current netbacks were implemented in June 2013. You will be provided with ample time to submit a ‘Permit Holder Netback Calculation’ form when required.

 In November 2014 the calculation parameters (netback, shrinkage factor, and oil equivalency factor) were updated with 2008 to 2012 industry data collected by CAPP. Prior to this date, the same parameters had been in effect since the program’s implementation in 2010. In the future, annual updates will be automatically implemented as the data becomes available.

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 Reclamation issued.

Producers: No, you do not have to complete this form unless you choose to dispute a required security deposit by submitting a dispute request to the Commission. Under the current LMR program, a universal netback is calculated for all producers based on current CAPP statistics.
Non-producers: Yes, you do have to submit this form upon request from the Commission if a Permit holder wishes to receive a deemed asset for a designated gas plant or disposal station. The netbacks used in the determination of a deemed asset for processors and disposers is based on an average of all submitted industry netbacks from the most recent year-end totalled and calculated individually for each non-producer category.
Permit holders that chose not to submit a netback will be given a deemed asset of zero. 
The industry average netbacks for non-producers will be valid for a period up to three years; sufficient notice will be given when the Commission is required or deems it necessary to update the industry average netbacks.

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.

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.

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.

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 .

LMR ratios for BC operators are posted to the Commission’s website here. Ratios are calculated and updated daily. An operator may also request an Operator Detail Report (a report that lists the deemed assets and liabilities for each individual permit held by an operator) by emailing .

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

At this time no further consultation periods will be held for the producer and non-producer programs.  That being said, the Commission is always open to feedback from stakeholders regarding our programs.

  • To access either of these applications you need to be granted Drill Comp Prod Rep access to our system. Each company has a company administrator that can grant you this access.
  • If you do not know who your company administrator is please contact and request the contact details.
  • Please note: You must create your login account before you can ask your company administrator for this access.

To get support please either:

Either of these two options will generate a call number that will be emailed back to you for future reference.

  1. Go to
  2. At the top of the website at the right, click "Online Services"
  3. Here you will find the Online Services/Applications that are made available by BCOGC. 
  4. One that may be of interest is "Data Downloads" that can be found in the "Web Applications" grouping.  You can log in with the login account you created on our website.
  5. Once logged in, click "MENU", then click "Data Downloads"

On the data downloads webpage you will find the following information

  1. Directional Surveys in pdf format for March 2009 onward.
  2. Other directional survey data
  3. Drilling data for wells in BC
  4. Hydrocarbon and by-products reserves in BC
  5. Monthly Drilling Reports
  6. Production data for wells in BC
  7. Unique Well identifier changes
  8. Well Index data (by various options)
  9. Other download data.

Before you can access a variety of the functionality on our website, you must create an account. You can create an account by doing the following:

  1. Go to
  2. At the top of the website on the right, click "Online Services"
  3. Under the grouping title "Additional Links", click "Create an Account / Change Password".
  4. Enter your email address and click "Submit" to start the process of creating an account. (PLEASE NOTE: Your email address is not your login. Your login will be emailed to you.)
  5. Follow the online form to complete your account.
  6. You should receive an automated email from our system with your user name (usually first initial last name).

**If you have any issues creating the account or if you do not get an email with your password please contact for support.

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.

KERMIT provides the functionality to:

  • Submit Pipeline and Facility Applications (New, Revisions, Amendments and Field Changes)
  • Submit Pipeline and Facility Construction Starts, Pressure Tests, Leave-To-Open's or As-builts
  • Submit Pipeline and Facility Notices of Intent
  • Respond to all inspection deficiencies and submit suspended well inspections
  • Submit Winter Stream Crossings
  • Search Pipeline Projects and Facility Sites
  • Manage user account security

You can access KERMIT through the "Online Services" page linked to in the upper right corner of

You will require an account with the OGC to access KERMIT.  You can set up a new account by clicking on the "Create an Account / Change Password" under the "Additional Links" grouping on the "Online Services" page.

Once you have created your login ID you must contact your company administrator and request the correct level of access to company data.

Your company administrator can grant the following types of access:

  1. Admin Deficiency Representative
  2. Applications
  3. Company Admin
  4. Drilling Comp Prod Rep
  5. DCP Admin
  6. First Nations Portal Read Only
  7. First Nations Portal Update
  8. Frac Fluid Reporting
  9. Geophysical Portal
  10. Incident Reporting
  11. Inspections Representative
  12. Invoice Reconciliation
  13. Notices
  14. Waste Disposal Representative

If you do not know who your company administrator is please contact and request the contact details.  For more details on the types of access listed above, please consult the External KERMIT Company Admin How To Document

The Area-based Analysis (ABA) approach has been developed by the BC Oil and Gas Commission (the Commission) as a framework for managing the impacts of oil and gas development. It is a different and more effective way of characterizing landscape of unconventional gas basins to inform decisions on oil and gas applications.

The Commission uses ABA to address the long-term effects of oil and gas activity in its decision making. Various decisions involving roads, water, seismic activity, well and facility locations, and pipeline corridors cause cumulative effects to both environmental and social values. Considering effects on only a project- or sector-specific basis can allow unintended impacts to accumulate over time.

In contrast, the Commission is addressing cumulative effects of oil and gas activity through the Areabased Analysis approach to permitting and authorizing. This approach allows the Commission to manage industry activity comprehensively to protect ecological, social and cultural heritage values. The actions that will be assessed are the combined footprint impact of industrial development on the selected values. For the Commission, that means that decisions about oil and gas activities will be made with all industrial development in mind.

Area-based Analysis considers all oil and gas activities and the surface and subsurface environmental impacts, both current and potential, at the full basin scale to achieve better environmental outcomes and more effective and efficient regulation. That means that broad impacts can be considered when looking at specific applications or activities, rather than just the localized effects of one permit. It evaluates the overall landscape – including features such as existingroads, wildlife management zones and other industrial users.

It’s an approach that manages environmental values based on direction set by government. ABA gives the Commission a better picture of the cumulative and larger impact of oil and gas activities for an entire region within the overall context of all activity. This information is used when the Commission makes decisions on applications.

Area-based Analysis follows the adaptive management process – the Commission will monitor to measure impacts, and adjust the overall framework as required.

Values includedTarget date
Hydro-riparian ecosystems, Old ForestFall 2014
High priority wildlife2015
Ground water
Air quality
First Nation cultural, heritage and traditional use


The ABA proof of concept was focused on landscape and ecological values within the Liard Unconventional Gas Basin. This ecological and landscape focus will be retained as ABA is deployed across the entire land base of northeast British Columbia (see Figure 2).


Compiling all known data and information into area-specific analyses gives industry, First Nations, government and other stakeholders the same information used by the Commission.

All documentation, data and analytical procedures used in ABA will be shared with all First Nations communities.

Area-based analysis integrates strategic direction from statutes, regulations and existing land-use plans with identified environmental and cultural values into a coherent and clarified framework.

This framework will:

  • Provide a consistent rationale and process for identifying environmental and cultural values.
  • Clarify objectives as set out in government policy and statutes.
  • Provide an analysis of all existing development and the opportunity for future oil and gas activity.
  • Provide a simplified and transparent framework to assess and manage oil and gas development impacts on identified values

The Area-Based Analysis (ABA) approach uses components of common cumulative effects assessment processes, but is geared to be operational. It will help inform decision makers about the impacts of oil and gas applications in the broader context of all development.

Area-Based Analysis is also used to evaluate trends in resource development and the effectiveness of policy regimes. Area-Based Analysis reports will be updated periodically to reflect new information, including updates to relevant government policy and legislation and new development activities.

The principle behind ABA is that as the impact to a value increases due to industrial build out by all activity, not just oil and gas, the management response escalates.

An assessment framework is developed for each value (see Figure 1) and the information generated during the assessment is provided to the Statutory Decision Maker for use in their decision.

The goal of the Area-based Analysis framework is to maintain conditions in the bottom bar where permitting is subject to routine reviews and operating procedures.

In the event the enhanced management trigger has been reached and the current condition of the value is determined to be in the middle (yellow) bar, the permitting process is subject to additional review and additional operating procedures will considered.

The objective is to return the conditions below the enhanced management trigger. FIGURE 1

In the event regulatory/policy trigger has been reached and the current condition of the value is determined to be in the top (orange) bar, the permitting process is subject to additional senior/regional staff review and additional operating procedures will considered.

The objective will be to restore conditions below the regulatory/policy trigger and ideally below the enhanced management trigger. This may include suspending permitting, confirming policy direction and implementing innovative approaches to mitigate the impact.

The framework is designed to be modular, and work is under way on five values:

  • hydro-riparian ecosystems (riparian habitat, water quantity)
  • old forest
  • high-priority wildlife habitat
  • resource features
  • cultural heritage resources.

Three additional values are planned:

  • ground water
  • water quality
  • air quality.

If additional values are identified through the First Nations engagement process, they will be considered for inclusion within the framework.

The measurement of disturbance will be assessed against triggers/thresholds that have been established by expert opinion. These thresholds will trigger actions that will reduce the impact of further development, by introducing avoidance and mitigation strategies. 

The actions that will be assessed are the combined footprint impact of all industrial development on the selected values. This includes all surface land use disturbance associated with oil and gas activity, geophysical activity, cutblocks and non-oil activity (such as mining, recreation, hydro, wind power, transmission lines). For the Commission, that means that decisions about oil and gas activities will be made with all industrial development in mind.

Area-based Analysis has been expanded to cover the full extent of the Western Canadian Sedimentary Basin in northeast British Columbia (NEBC). This includes the key development basins: The Horn River, the Cordova Embayment, the Montney and the Liard Basin.

The initial values being assessed focus on the biophysical components of the ecosystem. This includes 650,000 hectares of hydro-riparian reserves and 3.5 million hectares of Old Forest.

The ABA process monitors all industrial disturbance in a comprehensive incursion database.

Embodied in the existing environmental legislation and policy regime that governs resource management within British Columbia is the concept of “coarse-filter” and “fine-filter” management.

Coarse-filter management refers to the conservation of landscapes through networks of protected areas and management zones that allow natural processes to persist. Conserving the ecological communities of a given region through coarse filter management will also conserve those species that co-occur on the landscape, share common ecological processes and/or threats and are expected to behave similarly to development pressures and management actions.

Some species, ecosystems and features need to be conserved through individual, often localized efforts because they fall through the mesh of the coarse filter. This process is termed fine-filter management, and refers to conservation through localized protection measures such as individual species protection plans or protection of critical habitats or features (dens or rookeries) that are requisite for key life functions.

This framework was used to define the suite of starting values, as well as to help define the nesting of related values. The starting values are:

  • hydro-riparian ecosystems (riparian habitat, water quantity)
  • old forest
  • high priority wildlife habitat
  • resource features
  • cultural heritage resources

ABA fits into the existing legal framework within which the BC Oil and Gas Commission operates. This legal framework is an environmental protection regime that is embodied in the collection of acts, regulations, standards, practice requirements and management plans that govern the mandate of the BC Oil and Gas Commission.

The legal framework was developed over many years. It is based on a wealth of information and knowledge about the activities on the ground and/or the environmental components. Overall the legal framework is intended to balance scientific knowledge with management risk, while protecting the environment and enabling development.

ABA gives the Commission greater certainty that decisions about oil and gas activity are made within the legal framework and that the effects of oil and gas activity can be managed and mitigated effectively and to lasting effect.

Some of the specific concerns ABA will help address include:

Management/regulation concerns

  • Clarification of current legal/policy objectives in the Oil and Gas Activities Act (OGAA) and the Environmental Protection and Management Regulation (EPMR), which are both administered by the Commission.
  • In conjunction with the cumulative effects program of the Ministry of Forest Lands and Natural Resource Operations (FLNRO), the ABA will:
    • Address the situation that multiple government agencies permit and authorize different industries and activities that impact the same values on the same land base
    • develop common objectives and shared information to minimize or eliminate the accumulation of unintended impacts
    • ensure the assessment(s) informs decision-making in a coordinated and consistent manner across the natural resource sector in order to reduce unintended impacts on values
    • address the cumulative environmental effects of all natural resource activities and events on a select set of resource values (rather than just oil and gas, for instance).

Environmental concerns:

  • The ABA will assist in addressing concerns by
    • identifying and making coordinated decisions about significant resource development in northeast British Columbia
    • managing the impacts of development on key ecosystem attributes (habitat, water, air, species) to stay within acceptable levels
    • managing the impacts of development on the resource values that support the practice of treaty rights.

Area-based Analysis (ABA) 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.

One of the best methods to reduce 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. Sensitive data and information can be protected, and transparent and regular reporting on the information important to First Nations can occur.

Area-based Analysis was introduced to First Nations in conjunction with FLNRO’s (Forests, Lands and Natural Resource Operations) presentation on cumulative effects during two workshops in January 2013 in Fort St John. First Nations unanimously requested, and the FLNRO and the Commission committed to working directly with each community to define specific interests and next steps.

Since then the FLNRO and the Commission have participated in further engagement with all First Nations in the northeast region by providing background materials, holding face-to-face meetings with interested First Nations within their communities and distributing both the draft assessment report completed for the South Peace area and the methods paper for the ABA approach.

Many First Nations have chosen to work directly with the FLNRO and the Commission specifically on incorporating First Nations values of interest, providing additional data and reviewing the preliminary assessment methods and results.

Most Consultation Process Agreements (CPA) are being re-negotiated and alternative approaches such as ABA being brought forward in discussion with application consultation processes.

Area-based Analysis (ABA) is intended to provide a structured assessment of values for consideration in decision making. ABA could include an assessment of those resource values that are important to or contribute to the practice of treaty rights. Preliminary discussions have commenced with some First Nations communities on how to develop a structured assessment of specific environmental, cultural and heritage values within ABA that are tied to the practice of treaty rights.

They are not exclusive but they do meet different needs on different scales.

The Environmental Assessment Office ensures proposed major projects meet provincial environmental, economic and social goals, and the interests and concerns of B.C.’s families, businesses, communities and First Nations are considered in each assessment. The Environmental Assessment Office evaluates proposed projects that are reviewable under the Environmental Assessment Act for potential adverse environmental, economic, social, heritage and health effects and verifies and enforces compliance with the conditions of environmental assessment certificates. The projects subject to review are generally those with a higher potential for adverse environmental, economic, social, heritage or health effects.

The ABA framework was developed to be an ongoing component of permitting decisions within the Commission; it had to be implementable so that the concerns about cumulative effects could be more readily addressed. Adjustments in current permitting/authorization processes, additional data and new GIS (Geographic Information System) tools were required, and the stakeholder consultation critical to implementation success was needed.

ABA is designed to be adaptable so that when changes to legislation/policy are introduced, or existing values/objectives are modified, the Commission can easily introduce the changes to a system that is operating, and understood, accepted and supported by all involved. New additional environmental / cultural considerations can be added to the analysis when they are identified and provided sufficient spatial data exists and can be incorporated.

The Oil and Gas Commission’s Area-based Analysis (ABA) approach supports B.C.’s legal framework that manages values.

The Commission and the Ministry of Forest, Lands and Natural Resource Operations (FLNRO) have been collaborating on the development of ABA and the Northeast Cumulative Effects Assessment and Management (CEAM) demonstration project.

Both are a values-based approach to assessing and managing the cumulative effects of activity. Both ABA and CEAM supplement a comprehensive suite of natural resource policy and legislative tools that are in place to address cumulative effects in B.C.

These policy and legislative tools in turn provide a legal framework to proactively and comprehensively manage the cumulative impacts of development by multiple resources within the same region.

This encompassing system, or legal framework, includes:

  • Resource-focused legislation/policy providing both strategic and operational guidance for resource extraction, management and environmental protection.
  • Specific legislation to assess the cumulative effects of proposed major projects that have potential impacts over and above the resource-focused legislation.
  • A comprehensive land use and resource management planning system implemented over the majority of B.C.
  • Province-wide stewardship staff focused on monitoring the condition of the environment.
  • Formal engagement processes, formal consultation procedures and government-to-government agreements between First Nations Communities, the Government and the many ministries and agencies involved in the management of natural resources.

ABA and CEAM assist this system to achieve a more consistent and coordinated approach to cumulative effects assessment and management across the natural resource sector. They address the issue of multiple agencies permitting activities that impact the same values on the same land base.

The Commission and the FLNRO are developing one database to ensure consistency between both initiatives. ABA will be used as part of the Commission’s permitting and authorization process to assess the impact of proposed oil and gas activities considering the cumulative effects of all development activity.

In conjunction with FLNRO, key data input and assumptions will be validated through 2015 with a field assessment in the summer of 2015. Two specific areas that will be assessed include:

  • The accuracy of predicting a field-based riparian class assessment from an air photo interpretation of riparian features.
  • The reliability of the assumption that there has been no ecological succession, reclamation or reforestation on any disturbance, and that the impact that occurred with the initial disturbance has not changed, regardless of when it occurred.
  • The first priority for these reviews is the Lower Pine River water management basin.

In addition, the OGC will:

  • Continue to work with First Nations through community-focused engagement sessions to review ABA results and explore avenues for incorporating cultural heritage resources.
  • Unveil a public web site with all relevant documentation and data: January 2015
  • High priority wildlife value go live: 2015
  • Cultural heritage resources values go live: 2015
  • Other values (air quality, water quality, ground water): when ready

The principle behind ABA is that as the impact to a value increases due to industrial build out, management response escalates. The Commission has developed ABA-specific permit conditions to help address the incremental impacts of any activity. These conditions will be considered by Commission staff for all permits and authorizations for those values when the current condition is above Enhanced Management Trigger or above the Regulatory Policy Trigger. This will commence when ABA goes live.

As of January 2015, 27 of the 69 water management basins are above the Enhanced Management Trigger. All Natural Disturbance Units have sufficient Old Forest to meet the specified targets. These results are subject to change. Current ABA Status is available in the ABA shapefiles and Quarterly Reports.

Area-based Analysis (ABA) is a valuable tool for decision makers and resource managers to better manage the environment and minimize further impacts. ABA quickly draws attention to areas where significant cumulative effects exist and allows for a greater understanding of disturbance.

ABA will assess the combined footprint of all industrial development on the selected values. For the Commission, that means that decisions about oil and gas activities will be made with all industrial development in mind.

The best available information is used in ABA however because the data and the analytical techniques are necessarily simplifications of the real world, the technical information and analysis does not necessarily provide a complete picture of all aspects of the value, nor all answers or solutions.

Ongoing studies and monitoring will improve knowledge and increase certainty with time. All data have limitations, and usually require assumptions to use, which in turn creates strengths and weaknesses that need to be considered within a decision. Detailed documentation regarding input data, limitations, sourcing, and methodology is contained in the report “Project Analysis and Implementation: Area-based Analysis” available on the ABA web page, including the key assumptions for all input data.

The technical information and analysis does not provide the complete answer or solution to ABAfocused permitting or authorization decisions. To ensure a fair and equitable assessment, in addition to the information describing data / analysis uncertainty, an assessment of other risks will be provided in conjunction with the ABA assessment.

A comprehensive section on ABA is on the Commission’s website. The Commission has endeavored to provide all the documentation required to incorporate ABA in applications. We expect that the materials on this website will answer any questions or concerns. If you are unable to find the answer in the material available:

  • For comments/questions on the overall ABA program design and direction, next steps, permit conditions, planning considerations, and overall management please send an email to
  • For comments or questions about the data used, key assumptions, assessment methodology, discrepancies between the mapped data and field conditions, data errors, please send an email to

To make the most effective applications and avoid delays or returns, Industry should include ABA as an integral part of planning an oil or gas activity. ABA is about planning  oil and gas activities in a way that minimizes the footprint of activities, and reduces restoration / reclamation timeframes on environmental values.

  1. Review ABA Website
  2. Review the FAQs available on the ABA Website.
  3. Download the ABA Riparian Habitat dataset for use in development planning
  4. Download the ABA Old Forest dataset for use in development planning
  5. During the development planning process consider:
    • What is the current condition and status of Riparian Habitat in the development area?
    • What is the current condition and status of Old Forest in the development area?
    • How can I plan the activity to avoid Old Forest & Riparian Habitat?
  6. ​What can I do to minimize disturbance?
    • Use existing disturbance, unless doing so would result in a greater disturbance, greater safety risk, significant operational difficulty and/or negative environmental impacts
    • Consider low impact seismic techniques such as wireless technology and meandering lines
    • Use common access and shared corridors
    • Consider using winter access in old forest and riparian reserve zones
    • Leverage use of directional drilling and multiwell pads to minimize disturbance
    • Place auxiliary disturbance outside sensitive areas
    • Minimize new land disturbance
    • Implement strategies that will expedite reclamation
  7. During the development planning process review existing disturbance on the landscape and use this where possible to minimize impact on the ABA values 

Where ABA indicates that the condition of the riparian and old forest value do not exceed any triggers, existing regulatory requirements and associated guidance need be considered in relation to these values.

Where a trigger has been exceeded, the considerations identified above will be expected of industry as they prepare applications for submission, and additional permit and authorization conditions may be included to reduce the proposed impact.

As well, the Commission is actively:

  • Reviewing key data and assumptions in conjunction with the Ministry of Forests and Natural Resource Operations (FLNRO), Specifically the two organizations are working together to:
    • Determine, for each type of disturbance, the relevance and impact of ecological succession, re-vegetation, reclamation, restoration and forest management on the riparian and old forest values
    • Establish a collaborative field program to understand the accuracy of the inventory and GIS-based assumptions relative to field conditions
  • Reviewing the existing plans (LRMP’s & SRMP’s) for additional guidance supporting the refinement of triggers
  • Reviewing the policy process that helped create the triggers

If the results are material, ABA will be re-run, if not the results will stand as-is.

Appendix B of the EMPG provides minimal guidelines for Mitigation Strategy documents. 

In addition ABA Mitigation Plans should include:

  • An explanation of any efforts made to coordinate access and development with other industrial users with operations in the area.
  • A detailed rationale is required when the applicant does not demonstrate avoidance, use of existing disturbance or shared access.
  • A detailed account of any criteria that were considered to minimize the disturbance footprint in well site design, such as alignment to fit local topography, limited use of cut and fill, minimizing pad size, avoidance of sensitive areas and actions to reduce the number of trees harvested.
  • A detailed explanation and/or a map of any site specific measures employed to minimize disturbance to soil and vegetation including plans that minimize impact to the duff layer (such as limited stumping/grubbing, frozen ground access, use of rig matting, use of low ground pressure equipment and soil management for restoration).
  • A detailed explanation and/or a map of any site-specific measures employed to limit disturbance by the roadway, such narrowing the cleared width of the right of way and limiting ground disturbance for the running surface and ditch lines.
  • A detailed explanation and/or a map of any site-specific measures employed to limit disturbance by pipeline construction, such as use of trenchless technology and reduction of workspace requirements on either side of the crossing.
  • A detailed explanation and/or a map of any site-specific geophysical survey design elements used to minimize disturbance, such as avoidance, dead-ending at riparian zones, cutting restrictions limited to brush and understory, meandering avoidance, doglegs and mulch management.
  • A detailed explanation and/or a map of any site-specific remediation and/or prescriptions for restoration and recovery, including actions related to access control, spreading coarse woody debris, mounding, planting and/or seeding.
  • A detailed explanation of minimal disturbance strategies for activity in Riparian Reserve Zones. This should include an erosion risk assessment, sediment control, timing considerations, stability analysis, minimal tree felling (away from watercourse), re-establishing vegetation, contingency measures, and a post construction recovery and monitoring plan.
  • Rationale detailing operational need or relevant constraints to justify any exceedance of the documented expectations for well pad area.
  • A detailed account of any considerations that support the objectives of the area within which the activity is proposed
  • Any other information that may support the proposed development being permitted within the Old Forest or Riparian Reserve Zone as proposed.

Shapefiles delineating Old Forest and Riparian Reserves Zones can be downloaded from the Commission website. These shapefiles include ABA Status information in the attribute data of each Water Management Basins and Natural Disturbance Units. ABA status is reported as either “Normal”, “Enhanced Management” or “Regulatory Policy”.

Applicants should use these datasets in their constraints mapping and planning operations in the same way they would consider Parks and Protected Areas, Ungulate Winter Ranges and Wildlife Habitat Areas.  Avoidance is only expected for “Enhanced Management” and “Regulatory Policy” areas.

ABA areas should be clearly delineated on all Construction Plans submitted to the Commission where the ABA Status is “Enhanced Management” or “Regulatory Policy”.

Industry should avoid the Area-based Analysis locations where values are identified as “Enhanced Management” or “Regulatory Policy.”

Where this is not possible, then the following are some of the criteria industry should consider:

  • Proponents should maximize the use of existing or adjacent disturbance and plan their workspaces to reside outside of Old Forest and Riparian Reserve Zones.
  • Clearing requirements for wells and facilities (hectares) should be appropriate for the permitted activity. More clearing will be permitted for multi-well pads and development wells than exploration (wildcat and outpost) wells. Any development well pad should not exceed 1.4 hectares for the first well, up to 0.7 hectares additional hectares for a second well and 0.2 hectares for each additional well.
  • Activities should minimize ground disturbance, protect root and duff layers and create micro-climates suitable for regeneration or re-vegetation.
  • In both Old Forest and Riparian Reserve Zones, operators should minimize clearing widths within the right-of-way and limit the width of running surfaces.
  • Road networks should be designed to minimize the number of water crossings, total footprint, and new clearing. The class of new linear routes should not be greater than the road class of the route from which it originated.
  • Proponents should work with all other industrial operators, to share access and rights of way.
  • Geophysical programs should be designed to minimize the number of water crossings, use existing disturbance and demonstrate low- or minimal-impact seismic techniques.
  • Proponents conducting geophysical surveys should promote natural regeneration, and enhance ecological recovery through access control, managing the mulch layer, strategic tree felling/bending and spreading of coarse woody debris.
  • Access should be controlled upon completion of activities and during inactive periods to encourage natural regeneration.

ABA endeavors to reduce the cumulative impact of oil and gas activities by minimizing the footprint and environmental impact of activities. Wherever possible the Commission strives to see no new disturbance within Old Forest and Riparian Reserve Zones 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.

Effective Sept. 14, 2015, proponents are to notify the Commission of any impact to ABA “Enhanced Management” or “Regulatory Policy” Areas that will result from proposed oil and gas activity. ABA has been added to the Well, Geophysical, Road, Facility and Pipeline Application Form under Spatial or Identified Areas. Applicants must indicate if the proposed development affects an “Enhanced Management” or “Regulatory Policy” Areas. If an impact is reported, proponents are advised to upload a Mitigation Strategy and delineate ABA areas in the Construction Plans.


The Commisison considers Area-based Analysis (ABA) in reviewing applications under the Land and Habitat Review. Delegated and statutory decision makers of the Commission have a GIS-based system that evaluates the cumulative impact of proposed activities on ABA Values and highlights where there are changes to “Enhanced Management” and “Regulatory Policy” areas. 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.

What are the requirements for notification when a third party is conducting ground disturbance activities in proximity to an OGAA regulated pipeline?

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

Is five working days notice sufficient prior to undertaking a ground disturbance in proximity to an OGC regulated pipeline?

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

If a pipeline goes from one lease to another lease, (leases are touching, and no new tenure), do you submit under a pipeline application or a facility amendment?

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

Are we still required to report spills complete with written report within 14 days?

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

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.

The BC Oil and Gas Commission (Commission) has delegated authority to issue short-term water use permits under Section 8 of the Water Act. The Commission looks at a number of key points when reviewing water applications, such as runoff levels in rivers, other users and ecological values of the area. Community and ecological needs must be able to be sustained before a permit is issued and conditions may be attached to the permit. The Commission is a proactive regulator with the authority to intervene when necessary.

In most river basins, the total approved short-term water use is a fraction of the mean annual runoff. In 2012, 3.77 million m3 of water was reported as used. The water reported as used was 18.5 per cent of the total approved for use in 2012.

The volume of water used per well ranges from 10,000 to 70,000 m3 depending on the targeted formation. For the majority of basins, approved water use corresponds to less than 0.2 per cent of mean annual runoff. Actual water use as reported by the approval holders in individual basins is a small fraction of the approved water use, and was less than 0.075 per cent of mean annual runoff in all river basins between January and December 2012. Basins with the largest total approved water volumes as a percentage of mean annual runoff are listed in the Annual Report on Water Use in Oil and Gas Activities.

Provincial laws outline how the oil and gas industry must ensure water resources are protected during drilling and production operations. A number of measures are required to protect the water supply such as setbacks to maintain distance between water wells and drilling operations. Pressure-tested steel casings are cemented in place to prevent hydraulic fracturing fluids from migrating into freshwater aquifers, and the integrity of the casing can be evaluated to ensure it is maintaining an impermeable barrier. There has never been an instance of groundwater contamination due to hydraulic fracturing in British Columbia.

The water table is in most cases thousands of metres above unconventional gas target zones. Potable water is found between 18 and 150 metres down while unconventional gas target zones are typically at a depth of 2,000 to 3,200 metres.

When the well is no longer being used it is plugged with dense impermeable cement. The casing is cut off below ground and the well is capped.

Provincial laws ensure produced water never comes into contact with the environment. Currently, about 40 per cent of produced water is reused in hydraulic fracturing operations. Produced water is disposed of in deep injection wells or stored temporarily, both which are subject to strict regulations.

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.

Currently, 65 per cent of water used for oil and gas activities comes from surface water such as lakes and rivers. 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 between 0-200m underground.

There is an abundance of water in northeast B.C. but it needs to be managed carefully, for example by halting industry water withdrawals during periods of seasonal low flow and drought as the Commission did in both 2010 and 2012. The Commission has also launched hydrology modelling for Northeast B.C. and created a tool that gives water license and permit decision-makers access to stream flow data, water approval data and recognizes water availability for every river or lake in Northeast B.C.

A Fact Sheet defining water used in natural gas activities can be found here and an Infographic poster on how water is managed is found here.

The Commission publishes an annual water report and quarterly water data. The latest quartlerly water use summary can be found here. The 2012 Annual Report on Water Use in Oil and Gas Activities can be found here.

For each basin, the mean annual discharge and runoff are listed. A list of current Section 8 permits is also available on and is updated daily.

The Northeast Water Tool provides information for decision makers on current stream flow data and other water approvals.

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

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

Is a well permit required to do exploration for a groundwater source well?

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

In the 'Flaring and Venting' section, the venting rate is required. Is this the venting rate for the new installations or the venting rate for the entire site, including what already exists?

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

High level and high pressure shutdown devices. What are the rules for when and where we need to have high pressure and high level devices on vessels? Do we need a high level and high pressure shutdown device on vessels with more than 1% H2S?

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

Do we have to do a application for a tower with a scada device on it now with OGAA in effect?

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

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 ERCB Guide 20 and will I need a cement plug at surface?

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

The Commission, through its Business Transition Strategy, is optimizing its operations. The eSubmission project is part of BTS and is focused on all industry submissions being moved from paper to a standardized electronic format. The Commission has closed the Online Drilling and Reporting System and updated it with the eSubmission portal, which allows industry to directly submit a wider variety of submission types and notices. eSubmission will be continually expanded and enhanced to ensure that all submission types are covered and that the interface works efficiently for industry and the Commission.

The Well Data Submission Requirements Manual outlines to industry the required format for data submissions to the Commission. The file formats and naming conventions outlined in the Well Data Submission Requirements Manual are utlilized when submitting data via the eSubmission portal. The data types that are not currently processed via the eSubmission portal will retain the file formats and file naming conventions when they are integrated into the portal.

Yes, there is a submission log application within eSubmission that will allow you to track all well 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, however the DCP Admin role is required to access to the detailed submission log.  More details on permissions can be found here.

The date format portion of the file naming convention is always 7 characters.  The first 4 characters are always digits and represent the year.  For 2014, the YYYY is “2014”.  The second portion of the data format is for the month and is always three alphabetic characters.  For January, the MMM is JAN. The remaining months are FEB/MAR/APR/MAY/JUN/JUL/SEP/OCT/NOV/DEC.  The third and final portion of the data format is always two numeric characters.  For the first of the month, it is 01 and for the 22nd of the month it is 22.  Example: For September 3rd, 2014, it would be 2014SEP03.  The only exception to this is for injection and disposal, which are monthly statements whereby the file naming convention coincides with that month’s statement, where the file naming format is YYYYMM.  YYYY is a 4 digit year code and MM is the two digit month code, so for a May 2014 monthly injection and disposal statement, the date format is 201405.

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.

Each analyses should be a copy of the report in PDF and the associated PAS file.  PAS file business rules for GAN (Gas and Liquid Hydrocarbon), OAN (Oil) and WAN (Water) are outlined in the OGC PAS File Business Rule document. These files to the be uploaded using the eSubmission portal. Once an electronic copy has been submitted, a paper (hard copy) is not required. For additional information, please reference the Well Data Submission Requirements Manual.

Questions can be submitted to This email address is monitored daily and will either answer any questions about well data submissions or redirect any general questions about eSubmission to the applicable Commission subject matter expert.

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 Well Data Submission Requirements Manual.

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

A: If you have access to an electronic version of the file or scanned image, please send your query to Records and Information Services at You can also call the Well Data Help Line at (250) 419-4488.

By default browsers windows will share the same session and eventually you will start seeing expired pages in one or both browser windows. 


If you are using Internet Explorer (IE) you will avoid the problem as follows:

  1. Open IE and run Esub. (You will be asked to logon.)
  2. Open the second IE browser window. On the “File” pull down menu select “New session”. Now run Esub. (You will be asked to logon.)

If you are using Firefox visit the following and load the Multifox Add-on.

  1. Open Firefox and run Esub. (You will be asked to logon.)
  2. Open the second Firefox browser. Press the multifox icon on the browser toolbar and select “Private Profile”.  Now run Esub. (You will be asked to logon.)

If you are using Chrome you can load an Extension called Multilogin.

  1. Open Chrome and run Esub. (You will be asked to logon.)
  2. Open the second Chrome browser. Press the “New Identity” icon on the browser toolbar. Now run Esub. (You will be asked to logon.)

Another solution is to mix browsers. Different browsers technologies will not share sessions.

  1. Open Firefox and run Esub. (You will be asked to logon.)
  2. Open Chrome and run Esub. (You will be asked to logon.)

The online eSubmission system supports commonly used web browsers.

  • Internet Explorer 9 or higher
  • Firefox (v.25) or higher
  • Chrome (v.32) or higher

The Commission email can handle file sizes up to 100MB, but you’re encouraged to advise us when sending files in excess of 25MB.  Within the eSubmission portal, users can upload files up to 250MB in size.  If your files sizes exceed these limits or you have additional concerns, contact the Well Data Help Line at (250) 419-4488 and inform them of the issue.  The most likely resolution will be to copy the files to a CD/DVD and courier them to Well Data Management at the following address. All files contained with the CD/DVD must follow the prescribed file naming conventions, as outlined in the Well Data Submission Requirements Manual. You may include the data for several wells on a single CD/DVD.  Mailing address: Well Data Management, BC Oil and Gas Commission, 300 – 398 Harbour Rd, Victoria, B.C., V9A 0B7.