On May 19, 2022, the Province of British Columbia (the Province) released its new oil and gas royalty framework. The new framework will replace the current royalty framework that has been in place for 30 years. By Order in Council No. 263, the Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation, B.C. Reg. 495/92 is amended effective September 1, 2022 to allow for a transition between the current framework and the new framework. A general summary of the Province's new policy including the transition provisions is set out below.
What you need to know
- The new framework will result in increased royalty rates and fewer available royalty deductions.
- The system will be phased in starting September 1, 2022 with a short two-year transition period (compared to 10 years for Alberta’s), with full implementation by September 1, 2024.
- The minimum royalty rate is increased from three per cent to five per cent.
- The old reduction programs are eliminated and/or will be phased out by 2024.
- The new royalty system will include land healing and emissions reduction pools.
- Any unused credits will expire in four years unless transferred to the land healing and emissions reduction pools.
The policy announcement follows a review process that began with an independent assessment of the royalty system in place at the time. The independent assessment was released on October 6, 2021, finding that the current system was inefficient, overly complex and had high compliance costs for industry and administrative stakeholders, as well as high auditing costs for the government.
On November 10, 2021, the Province released a discussion paper summarizing options for reforming British Columbia’s natural gas royalty framework. The Province invited online comments on the discussion paper from stakeholders, interest groups and the general public. In January of 2022, the Province released a “What We Heard Report” summarizing the feedback it received on the discussion paper. The Province then made its policy announcement on May 19, 2022, but the Province will continue to engage stakeholders on details of the forthcoming royalty framework.
The new framework is based on a revenue-minus-cost royalty system, which charges a lower royalty rate while capital is being recovered. The new framework will use a minimum royalty rate of five per cent during the pre-payout period (the period beginning at initial production and ending when revenue from a well exceeds the total capital costs for drilling and completion). Price-sensitive royalty rates will apply once revenues from a well exceed capital costs. The specific range of price sensitivity will vary by commodity type, but will fall between five per cent and 40 per cent. The minimum royalty payable will be five per cent of monthly production, which is an increase from the current three per cent.
According to the Province's “What We Heard Report,” 41 per cent of survey respondents indicated that a flat rate on production with no capital recovery mechanisms was their preferred option for royalty structures. In contrast, industry representatives tended to favour the revenue-minus-cost model.
However, despite industry support for the current royalty credit system, the Province has announced significant changes to the credit system. These changes are set out more fully below, but the Province has elected to end certain deductions and has indicated that credits will now expire in four years unless transferred to a specific pool that will fund certain projects.
In terms of timing, the “What We Heard Report” indicated that, while not all submissions commented on timelines, of the ones that did, respondents that supported a flat rate with no recovery model also supported as short a transition period as possible (one and a half to two years) and did not support extended transition periods for existing wells. The majority of industry and association respondents supported extended transition periods for existing wells and/or honouring royalty credits that had already been earned. Despite the comments from industry stakeholders, the Province has elected for a transition period of two years, with full implementation by September 1, 2024.
The Province intends to implement the new framework September 1, 2024. However, a transitional system will take effect on September 1, 2022. The two-year transition period to the new framework is relatively quick. By comparison, in 2017, Alberta announced a 10-year transition period to modernize its royalty system.
Wells drilled after September 1, 2022, will be subject to a five per cent royalty rate for the equivalent of the first 12 production months (8,760 production hours). Following that, these wells will pay the prevailing price-sensitive royalty rates.
For current wells, and any wells where drilling commenced prior to September 1, 2022, the current royalty framework will apply until September 1, 2024. After September 1, 2024, these wells will not be eligible for rate reductions under the Marginal Well Royalty program, the Ultramarginal Royalty program, the Low Productivity Royalty program or the Clean Growth Infrastructure Royalty programs. Any deep wells with unused deep well deductions will be able to use those deductions to reduce royalties owed until September 1, 2026. After this date, those unused deductions will expire.
Land healing and emissions reduction pools
Starting in early 2023, producers will have the option to transfer unused deep-well deductions to a land healing and emissions reduction pool before September 1, 2026. The concept of transferring credits to a land healing and emissions reduction pool developed through engagement with industry, environmental and First Nations groups. The pool is intended to support work that goes above regulatory requirements to reduce emissions or cumulative impacts on the land base.
The Ministry of Energy, Mines and Low Carbon Innovation will conduct annual calls for projects from producers that wish to undertake work to qualify for deductions from their land healing and emissions reduction pool. Producers will be able to reduce royalties equal to expenditures on projects approved through these annual calls up to the value of deductions they have available in their pool.
Calculating costs under the revenue-minus-cost framework
A revenue-minus-cost royalty framework determines when price-sensitive royalty rates should apply by comparing the cost to put a well into production with the revenues earned from that well. The Province has indicated that specific cost policy is still under development, but specified that it will consider costs related to gathering and processing, as well as drilling and completion.
Within six months of a new well commencing production, producers will be required to submit cost data, as the new framework will seek to use actual costs when accounting for drilling and completion costs. The methodology to determine what costs are eligible to include in setting these costs will be aligned with existing taxation standard Canada Revenue Agency – Canadian Development Expense.
Price data and audits
The new framework will use actual costs when accounting for drilling and completion costs. The cost submissions will be subject to audit. The requirement to submit actual cost data may lead to additional time required to keep track of actual costs for each well, particularly where there is shared infrastructure amongst producers.
Oil and gas producers in British Columbia will need to prepare for the incoming changes to the royalty framework. While details of the framework are still forthcoming, the above provides a general overview of incoming changes.
The Province has stated it will continue discussions with First Nations, industry, environmental groups and other stakeholders to provide further clarity to the new royalty framework. In particular, the Province will engage various stakeholders to further develop and define allowable cost-policy, amounts contained within the drilling and completion amounts and the scope of activities supported through land healing and emissions reduction pools.
We will continue to monitor the developments in the new oil and gas royalty framework. For further information, please contact the authors listed below or anyone else in BLG's Energy team.