While global energy markets have shifted over time, Alberta’s production has also changed. Most easy-to-access conventional oil and gas fields have been depleted.

A typical well today looks a lot different than one drilled 30 years ago, or even 10 years ago. 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 are all important context pieces to consider when looking back at Alberta’s royalties over a period of time.

Emissions graph

Timeline

In the early years, Alberta followed a royalty system similar to the United States whereby the royalty was a fixed flat percentage such as 5%, 12.5%, or 16.67%. Following the first oil price shock in the early 1970s Alberta refined its royalty formula to make it sensitive to change in prices. At that time, distinction was made between “Old” production and “New.”

In 1978, the royalty formulas were also made sensitive to the level of production from the well.

In 1992, royalty rates were modified and an additional vintage distinction, called “Third Tier”, was introduced for conventional oil pools discovered after August 31, 1992.

Incentive programs were introduced in the 1980s in response to low prices. Most of these programs have now been removed. The generic oil sands royalty was introduced in 1997. 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 fiscal system design and application. This approach was manageable, given the small number of commercial oil sands projects in Alberta at the time.

However, it 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 oil sands development increased, it became obvious that a formal generic royalty structure for the oil sands sector was required.

The following are the major milestones in Alberta’s royalty system.

  • 2016

    Alberta's Modernized Royalty Framework is released on January 29th.

    The Petrochemicals Diversification Program is announced in February to encourage companies to invest in the development of new Alberta petrochemical facilities by providing up to $500 million in incentives through royalty credits.

  • 2015

    In June steps towards a climate change strategy and a royalty review chair are announced to set up the 2015 Royalty Review Panel.

    The Alberta Royalty Review commences in August.

    Community engagement sessions are announced in September.

    Telephone town halls with more community sessions are held in October.

  • 2013

    On June 17, 2013 the Alberta Energy Regulator (AER) takes over to provide full-lifecycle regulatory oversight of energy resource development in Alberta.

  • 2010

    October Energizing Investment Industry Royalty sessions are held:

  • 2008

    The Bitumen Valuation Methodology (Ministerial) Regulation (0.5 MB) is implemented on January 1, 2009.  The BVM determines a value to calculate oil sands royalty for bitumen produced in oil sands royalty projects where all or a substantial portion of the production is either upgraded on site, or sold or transferred to affiliates.

  • 2007

    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). The decision follows a review and consultation with industry and stakeholders.

  • 2004

    For the first time in Alberta's history the total annual bitumen production exceeded one million barrels per day.

  • 2002

    Natural gas royalty framework is revised to be based on in-stream components.

  • 1997

    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.

  • 1995

    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.

  • 1994

    Initial implementation of the new royalty system (a result of the 1990-92 Royalty Simplification project). Industry submits estimated royalty payments.

  • 1993

    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.

  • 1990

    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.

  • 1988

    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.

  • 1986

    Federal government deregulates natural gas prices.

  • 1985

    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.

  • 1978

    Low productivity feature for gas royalty introduced.

  • 1975

    Natural gas prices in Canada become regulated under Federal-Provincial agreement.

  • 1974

    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.

  • 1973

    Prime Minister Pierre Trudeau decrees "made in Canada" crude oil prices.

    Alberta implements a price sensitive royalty regime, rather than a fixed rate.

  • 1972

    Alberta proposes a mineral tax assessment on remaining recoverable crude oil reserves at fair value with no change in the existing royalty structure.

  • 1962

    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.

  • 1951

    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%

  • 1948

    The Alberta royalty rate is capped at 16.67 %

  • 1947

    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.

  • 1941

    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.

  • 1938

    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)

  • 1935

    The flat royalty rate on oil and gas is increased to 10%, with flexible treatment of low-value natural gas liquids.

  • 1930

    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.

    Royalty rate is set at a 5% flat rate on oil and gas.

  • 1915

    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.