BCOGC releases more details on BRFN agreement

FORT ST. JOHN, B.C. — The BC Oil & Gas Commission (BCOGC) and the ministry of energy have provided further guidance for the oil and gas industry regarding new rules under the Blueberry River First Nation (BRFN) agreement.

Announced on January 18th, the agreement responds to a 2021 decision from the B.C. Supreme Court, which found the province had infringed on BRFN’s Treaty 8 rights by allowing industrial development in the band’s traditional territory.

The agreement contained new guidelines specific to the oil and gas industry, including limits on new disturbances in high-value (HV1) areas, which the province aims to achieve by maximizing land protections and curbing new disturbances in the claim areas by 50 per cent.

These high-value areas, split into three categories — HV1A, HV1B and HV1C — are based on the future ability for new disturbances from oil and gas activities.

The province defines ‘new disturbances’ in the agreement as all oil and gas activity-related disturbances on Crown land, excluding any permitted and pre-existing oil and gas projects identified in the commission’s surface land use (SLU) data.

According to the commission’s release, oil and gas activity includes both “conventional and unconventional” oil and gas exploration and development, including coal bed gas, hydrogen development, carbon capture development and other forms of exploration and development that may emerge in the future.

Overall limits, potential locations and the manner of any new disturbances will be managed through the province’s new cumulative effects management framework.

HV1A areas (shown in purple on the map above) are on the outer limits of Montney. In the BRFN agreement, the province committed to a 100 per cent protection rate from new oil and gas disturbances in these areas, with existing oil and gas operations expected to be wound down at the “end of their useful life.”

The province said that existing infrastructure and wells could continue to operate and produce until they deplete. As long as no new disturbances are required, other pre-existing facilities outside the HV1A area can operate as well as be enhanced or expanded.

The commission will allow additional pipelines to “tie in” outside wells to existing gas processing facilities as long as they follow pre-existing corridors in the relevant location in the HV1A area.

It will also accept workspaces needed for ongoing operation and maintenance of pre-existing infrastructure if the applicant applies the principles for limiting new disturbances.

BRFN could agree to exceptions to these measures on a case-by-case basis, according to the BCOGC release.

The province said it will aim to have HV1B areas (shown in orange) 80 per cent protected from new disturbances. The commission won’t consider applications for these areas that propose new disturbances for two years, and even then, the application has to be consistent with an approved HV1 plan. 

However, the commission will consider applications that don’t require a new disturbance subject to consultation.

Areas identified as HV1C (shown in chartreuse or green) are within HV1A and B areas, or along the Alaska Highway, and have a committed 60 per cent protection rate. The province said the commission won’t consider applications in these areas requiring new disturbances during HV1 planning. However, those that don’t create a new disturbance will be subject to consultation.

The province said that HV1 plans will only focus on oil and gas to identify and verify where restoration activities will occur, what locations are suitable for development and where new disturbance protections should be.

There are four expected waves of HV1 plans, the first of which is called “the Gundy Complex” and is within HV1C. The province expects this plan to be finished by November 2023.

The second wave in HV1C is called “Grizzly Creek.” It’s scheduled to be completed by April 2024.

Upper Halfway is the third wave of HV1 plans. Also in HV1C, the province said it expects the plan to be finished by June 2024.

The fourth and final plan is working on all the HV1B areas together or “based on a sequence as learned through the first three waves on HV1C.” According to the province, one or multiple HV1B plans have a target completion date of February 2025.

The BCOGC will receive “binding direction” from the province through a legislative mechanism to make sure that it can review applications with the new rules in place.

New oil and gas applications must show the applicant’s efforts to merge a new disturbance with any existing disturbances and outline all project and activity components that require authorization, regardless of whether they’re part of the subject application.

Applications also need to include a pre-engagement report that shows the process used by the applicant to engage BRFN. This report must describe any support, objections or concerns raised by the First Nation and detail how the applicant will address those concerns.

According to the commission’s release, companies looking to apply for an oil and gas permit in BRFN trapline areas must engage with the holder of the trapline to identify satisfactory locations for activities before making its application, which must include details such as how engagement with the trapline owner went and if the owner consented to the proposed application. The province said it will release detailed expectations for this type of engagement in the future.

In recognition of applications that were submitted to the commission before or during consultations with BRFN, the agreement lists existing applications in two categories — existing priority applications and existing applications. 

The province reportedly created the priority applications list after communicating with companies and in negotiations with BRFN. 

According to the province, the commission will review applications on the priority list through an “expedited” process to reach a decision. It will review applications that are not on the list following the new processes described within the agreement.

New oil and gas disturbances within the BRFN claim area are now subject to an annual cap of 750 hectares, split into three predominant areas — Area 1, Area A and the remaining part of the claim area.

Area 1 will have an annual sub-cap of 200 hectares, with a limit of 35 kilometres of new linear disturbances per year.

Area A will also have a sub-cap of 200 hectares per year to be replaced by a new sub-cap after negotiations between BRFN and Halfway River First Nation in the Cameron River Watershed basin conclude. According to the commission’s release, the province must also agree to the new sub-cap before it’s implemented.

The rest of the claim area will be subject to the remaining 350 hectares per year limit.

The commission will allocate the new cap. If it’s not fully used in a calendar year, the rest of the cap will carry forward to the next year. The province said BRFN and the provincial government will review caps annually to ensure restoration and planning have progressed enough to consider the allotted amount.

A $60K per hectare disturbance fee will apply for all new disturbances in the HV1, trapline, and priority WMB plan areas. The fee will be a condition on the applicant’s permit, with the funds going to the BRFN-B.C. Restoration Fund.

The province said it will share more details on how companies can make this payment in the future, adding that it may consider a disturbance fee credit if the company has already made payments to BRFN for similar purposes. However, confirmation from the band is required in this situation.

Tenure holders with over two per cent of the Montney tenure within the applicable cap application area will receive an initial portion of the 375 hectares based on the proportion of their holdings.

According to the province, the commission will measure this allocation based on tenure holdings at the beginning of the calendar year. The commission won’t consider tenure holdings bought or transferred after the allocation process until the following year.

Companies will work with the BCOGC to identify priority applications and establish what will apply to their tenure-based allocation, with conversations to begin late in the previous year or early in the year through March of the allocation year.

If a company cannot identify its priority applications that use its tenure allocation, the commission will add the remaining land to the discretionary allocation envelope for the tenure-holding area.

The BCOGC, directed by the ministry, will then distribute the remaining 375 hectares based on how the overall development plan and application package aims to minimize cumulative effects and uses nearby existing disturbances, the degree to which an applicant can show they addressed any outcomes of the pre-engagement with First Nations in their development proposal or application and “a consideration of the alignment of applications with three-year development interests and overall plan.”

According to the release, the commission will prioritize applications for common infrastructure over a “one-off” development project.

It will also consider the timing of the development within the three-year plan — whether an application can be deferred to the next year or if the company has rationalized the need for development in the current year — as well as economic significance, investment and dependencies related to the proposal.

If the discretionary allocation is not fully used, the commission will hold the balance of the envelope until its mid-year review.

Companies that don’t receive a tenure-based allocation will be considered for a discretionary allocation before those who got a tenure-based allocation.

However, the commission said that it aims to “balance the needs of companies that received a tenure-based allocation for additional new disturbances with the needs of companies who didn’t get an allocation based on tenure.”

The ministry is looking for feedback on its proposed allocation principles. Residents and industry can send their feedback and comments to [email protected] until February 9th, 2023.

For more details, view the ministry and commission’s joint release below.