- New mandatory public health measures in effect April 6.
- Many Albertans 16+ are now eligible to get vaccinated. Book your shot.
Global energy markets have shifted over time, along with Alberta’s production profile. Most easy-to-access conventional oil and gas fields have been depleted and production has shifted to higher cost bitumen extraction in Alberta’s three oil sands areas.
A typical well today looks a lot different than one drilled 30 years ago, or even 10 years ago. Horizontal drilling has become the norm in thermal, in-situ resource extraction. In addition, the oil sands resource – which only 15 years ago represented a small fraction of total royalties – now makes up the majority of royalty revenue.
These factors are all important considerations when looking back at Alberta’s royalties over a period of time.
The generic oil sands royalty system was introduced in 1997 to encourage investment in, and development of, Alberta’s oil sands resource. Prior to this, royalties for oil sands projects were prescribed in separate Crown agreements, or contracts, for each project. This produced an ad hoc approach to development and royalty collection, but was manageable, due to the small number of commercial oil sands projects in Alberta at the time.
But this was a time-consuming process, and did not provide certainty about the royalty treatment for future projects, or a level playing field across all projects. As interest in the oil sands resource increased, it became obvious that a formal generic royalty structure for the oil sands sector was required to provide greater certainty to companies participating in oil sands development.
The following are the major milestones in Alberta’s royalty system.
Taking effect in July 2019, the Royalty Guarantee Act provides certainty that no major changes will be made to the current oil and gas royalty structure for a period of at least 10 years.
The Alberta Royalty Review, initiated in 2015, resulted in changes to several petroleum, natural gas and oil sands royalty related regulations that came into effect on January 1, 2017. The updated regulations included:
- Oils Sands Royalty Regulation, 2009
- The Mines and Minerals Administration Regulation
- Oil Sands Allowed Costs (Ministerial) Regulation
- The Bitumen Valuation Methodology (Ministerial) Regulation
- The Dispute Resolution Regulation
In June, steps towards a climate change strategy are announced.
On August 28, 2015, the Government of Alberta announced the establishment of the Royalty Review Advisory Panel. The mandate of the Panel was to identify opportunities to optimize Alberta’s royalty framework for crude oil and liquids, natural gas and oil sands.
On June 17, 2013 the Alberta Energy Regulator (AER) takes over to provide full-lifecycle regulatory oversight of energy resource development in Alberta.
Energizing Investment Industry Royalty sessions were held in October.
The Bitumen Valuation Methodology (Ministerial) Regulation is implemented on January 1, 2009. The Bitumen Valuation Methodology provides a method that is used to determine the value of bitumen in the calculation of royalty for oil sands projects where 40% or more of production is either upgraded on site, or sold or transferred to affiliates.
The Government of Alberta tasks an independent, expert Royalty Review Panel to examine the province's energy royalties and tax regime. The panel is asked to focus on all aspects of the royalty system, including oil sands, conventional oil and gas, and coalbed methane. Their report (2.7 MB) is released on September 18th.
Premier Stelmach announces Alberta’s New Royalty Framework (1.0 MB) on October 25. The Framework sees increased royalties generated by an internationally competitive energy industry.
The Alberta government eliminates the Alberta Royalty Tax Credit Program (ARTC).
For the first time in Alberta's history the total annual bitumen production exceeds one million barrels per day.
Natural gas royalty framework is revised to be based on in-stream components.
The generic oil sands royalty regime, the Oil Sands Royalty Regulation, 1997, comes into effect on July 1, 1997, establishing generic royalty terms for all new oil sands projects. At the same time, the federal government extends its accelerated capital cost allowance to oil sands projects to encourage their development.
Industry feedback indicates that royalty and related administration cost are approximately one third of the pre ‘94 level. Industry and royalty business rules and business practices continue to evolve as part of the 1990-92 Royalty Simplification project.
A generic royalty regime for new oil sands projects is recommended to provide a smaller royalty share at the beginning of a development and a larger share for the government after the developers have recovered their costs. This concept is based on The Oil Sands: A New Energy Vision for Canada, a report prepared by the National Task Force on Oil Sands Strategies.
Initial implementation of the new royalty system (a result of the 1990-92 Royalty Simplification project). Industry submits estimated royalty payments.
Major royalty changes are introduced, including increased price sensitivity and select price inflation indexing.
A third tier vintage is introduced, and heavy oil vintages are separated from light.
Royalty rates are modified and an additional vintage distinction, called “Third Tier”, is introduced for conventional oil pools discovered after August 31, 1992.
The Royalty Simplification project is initiated by the Minister of Energy and Industry to streamline royalty calculation and processing. It continues in 1992 with an industry CEO on the steering committee.
Alberta Energy publishes a monthly Alberta Average Market Price (AMP) for natural gas/residue gas, given in units of $/1000 3 and $/GJ. This test specifies that the minimum valuation price that may be applied to the Crown's royalty share of production is 80% of the AMP ($/GJ) in effect during the month of sale. The AMP is effective for the production years 1988 to 1993.
Federal government deregulates natural gas prices.
The federal government deregulates oil prices and opens Canada's borders to imports and exports.
Oil Royalty holiday programs are introduced to reward successful explorers where previous grant-oriented programs only favoured activity.
The royalty formulas are also made sensitive to the level of production from the well.
Natural gas prices in Canada become regulated under Federal-Provincial agreement.
Oil and natural gas pools are classified by "vintage" for royalty calculation purposes. Vintage refers to the date of discovery of the oil or gas pool from which production occurs. "Old" refers to oil and gas discovered before 1974; "new" refers to oil and gas discovered after 1973. Royalty rates for production from newly discovered pools are set lower to reflect the higher average finding and development costs associated with newer smaller pools.
The Alberta Petroleum Marketing Commission (APMC) is created by the Petroleum Marketing Act. The Commission becomes the provincial Crown corporation responsible for selling conventional crude that the Alberta government receives in lieu of cash royalties.
Prime Minister Pierre Trudeau decrees "made in Canada" crude oil prices.
Alberta implements a price-sensitive royalty regime, rather than a fixed rate.
Alberta proposes a mineral tax assessment on remaining recoverable crude oil reserves at fair value with no change in the existing royalty structure.
The number of steps in oil royalty is reduced to 3.
The royalty rate on gas is increased to 16.67% with minimum deemed royalty value maintained.
A sliding scale for royalty rates is established in Alberta Royalty Regulations.
Royalty rates on oil vary with production with 8 steps from 5% to 16.67%
The Alberta royalty rate is capped at 16.67 %
After drilling 133 dry holes across Western Canada, Imperial Oil strikes oil at Leduc, Alberta, on February 13, transforming Canada into an oil-rich nation.
Alberta shifts the royalty rates on oil from a flat rate of 10% to a choice of a 12.5% flat rate or a 5 - 15% royalty based on production levels.
The Petroleum and Natural Gas Conservation Board is established. It later becomes the Energy Utilities Board (EUB), then becomes both the Energy Resources Conservation Board (ERCB) and the Alberta Energy Regulator (AER)
The flat royalty rate on oil and gas is increased to 10%, with flexible treatment of low-value natural gas liquids.
Under the Natural Resources Transfer Agreement, the Dominion of Canada transfers all mineral, oil and natural gas rights to the province of Alberta.
First Alberta Royalty Regulation.
Alberta follows a royalty system similar to the United States with a fixed flat percentage royalty rate such as 5%, 12.5%, or 16.67%. Following the first oil price shock in the early 1970s, Alberta refines its royalty formula to make it sensitive to change in prices. At that time, a distinction is made between “Old” production and “New.”
The Public Utilities Board (PUB) becomes Alberta’s first regulatory agency with the primary responsibility of regulating utility rates and service. It later becomes the Petroleum and Natural Gas Conservation Board.