Oil and natural gas producers that access and develop publicly owned resources in the Province of British Columbia must pay either a royalty or a freehold production tax to the Province. The royalty rates are based on oil and natural gas prices, volume of production, and may be subject to deductions through government royalty programs.
On September 1, 2022, the Province will begin a two-year transition period to implement a new oil and gas royalty framework, through an amendment to the Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation, B.C. Reg. 495/92 by Order in Council No. 263 (May 19, 2022). This new framework will feature an increased minimum royalty rate and the elimination of certain deduction programs. The new framework will replace the existing framework, which has been in place for nearly three decades, and responds to the significant recent changes in drilling technology, market conditions, and environmental protection concerns.
This change came as a response to the Province's Ministry of Energy, Mines, and Low Carbon Innovation's launch of an independent assessment of the existing royalty system. The report found that a new system should be simple, low in cost, accountable, transparent, and efficient. In addition, the Province undertook public engagement on the results of the report from November 10, 2021 to December 10, 2021 and as a result, produced the What We Heard Report in January 2022. Through this process, stakeholders, interests groups, and the general public were invited to provide their opinion in an online survey.
Key Points of Interest
- The new system is based on a revenue-minus-cost system with price-sensitive royalty rates.
- The minimum royalty rate will increase from 3% to 5% of monthly production.
- A two-year transition period will commence on September 1, 2022 whereby wells drilled after this date will be subject to a 5% royalty rate for the equivalent of the first twelve production months (8,760 production hours). On September 1, 2024, all wells will be subject to the new price-sensitive royalty rates.
- The new system will eliminate many royalty deduction programs, including the Deep Well Royalty Program.
- There is an option to transfer unused royalty credits to land healing and emissions reductions pools before September 1, 2026. Otherwise, they will expire.
Summary of the New Policy
The New Framework
The new system is based on a revenue-minus-cost method. Within the framework, a 5% royalty rate will apply to a new well until the total capital costs for drilling and completion exceeds its revenue (the pre-payout period). Once revenues from a well exceed its actual capital costs for development, a price-sensitive royalty rate between 5% and 40%, depending on the commodity type, will apply.
The Province plans for additional engagement with oil and gas stakeholders during the summer of 2022 to develop and define a policy surrounding allowable-costs.
i. Rates for Existing Wells (those drilled before September 1, 2022)
Until August 31, 2024, existing wells and those that begin drilling before September 1, 2022 will be continue to be subject to the current royalty framework, with the minimum royalty rate at 3% of monthly production. Effective September 1, 2024, these wells will be subject to the incoming price-sensitive royalty rate, which increases the minimum royalty rate to 5% of monthly production.
ii. Rates for New Wells (those drilled as of September 1, 2022)
Wells drilled as of September 1, 2022 will pay a 5% royalty rate for the equivalent of the first 12 production months (8,760 production hours), during the transition period. At the end of these 12 production months, these wells will revert to the prevailing royalty rates. On September 1, 2024, all wells will be subject to the price-sensitive rates under the new system.
Elimination of Royalty Programs and New Pools
The new royalty system excludes existing wells (as of September 1, 2024) and new wells (as of September 1, 2022) from eligibility for the:
- Deep Well Royalty Program;
- Marginal Well Royalty Program;
- Ultramarginal Royalty Program;
- Low Productivity Royalty Program; and
- Clean Growth Infrastructure Royalty Program.
The largest of the five programs, the Deep Well Royalty Program, was implemented to offset higher drilling and completion costs incurred by wells that are considered particularly deep, amassing several billion dollars of deductions for producers since its creation in 2003.
Producers with unused deep-well credits can continue to use the deductions to reduce royalties owed until September 1, 2026. At that point, existing credits will expire unless transferred to environmentally focused land healings and emissions reductions pools. Within this new system, the intention of the pools is to support initiatives that reduce emissions or cumulative impacts on the land. These environmental projects must go beyond regulatory requirements to be eligible. Once transferred, these credits may not be used to reduce royalties on the well they were originally associated with, nor may they be transferred between producers' pools (with an exception for corporate acquisitions).
The window for producers to transfer their unused deductions will be open between early 2023 and September 1, 2026. Throughout this time, the Ministry of Energy, Mines and Low Carbon Innovation will conduct calls for projects that qualify for the use of these credits.
Implications for B.C's Energy Sector
The new framework is reported to be less complex; however, in determining the price-sensitive royalty rates, the revenue-minus-cost based framework will require producers to submit a new well's actual capital costs within six months of commencing production. Producers must be aware of this requirement as all costs must now be tracked. These cost submissions will be subject to audit and will consider costs related to gathering, processing, drilling, and completion. Specific cost policy is under development and will be aligned with the existing taxation standard of the Canada Revenue Agency (Canadian Development Expense).
The two-year transition period to implement the new framework on existing wells is considerably shorter than Alberta's 10-year transition period to adopt their new royalty framework. The more rapid British Columbia transition period is being brought in through relatively quick successive stages, leading to some speculation of a "dash for gas" as new wells may be rushed to be approved and built before the new regulations come into full effect. The implications of this possibility may be amongst important considerations for producers in the coming months.
British Columbia is a significant producer of energy resources and an efficient royalty regime is necessary and beneficial for the industry and the Province.
The foregoing provides only an overview and does not constitute legal advice. Readers are cautioned against making any decisions based on this material alone. Rather, specific legal advice should be obtained.
© McMillan LLP 2021