Alberta’s New Royalty Framework

Courtesy of Osler. View original article here.

On Friday, January 29, 2016, the Alberta government released the results of its Royalty Review Advisory Panel (the Panel), ending the considerable uncertainty that the announcement of the review first created. Much was riding on the outcome of the review, both economically for the oil and gas industry, and politically for the Alberta NDP.

Acceptance of the Panel’s Recommendations

The government announced that it would fully accept the recommendations contained in the Panel’s report, without any additions. The Panel’s report concluded that the current royalty rates for oil sands are appropriate and should be maintained, with some minor adjustments to allowable costs and transparency. The report recommended that the modernized royalty framework be implemented as of January 1, 2017, and that any wells drilled before that date pay royalties under the existing framework for a 10-year period. The new royalty framework will also implement a revenue minus cost (RMC) structure, intended to encourage efficiency and enable operators to more accurately predict payout periods for capital projects. Additional details are to be unveiled by March 31, 2016, including the specific royalty rate formula and certain “value-add” incentives.

Highlights of the New Royalty Regime Effective January 1, 2017

The complexity of Alberta’s existing royalty regime is well known, and Premier Notley’s signal that the new regime would be predictable and straightforward without increasing producer costs in the near future was welcome
news.[1] While a sliding scale royalty is maintained, it will be achieved with a greater degree of simplicity than under the existing regime. The new royalty percentage will be applied to the gross revenue generated from all hydrocarbons, eliminating the need to label a well as either “oil” or “gas.” The RMC framework will replace the various royalty credits and holidays available under the current regime. Wells will be charged a flat 5% royalty rate under the new framework until revenues exceed a normalized well cost allowance, which will be based on vertical well depth and lateral length (for horizontal wells). The amount of this cost allowance is still to be determined, but the combined effect of these changes may incentivize low-cost producers to drill more wells and encourage high-cost producers to reduce their costs, while also eliminating the potentially adverse economic consequences resulting from foregone incentives when the hydrocarbons recovered are different from the hydrocarbons targeted.

Competitiveness of Alberta’s New Royalty Framework

Perhaps the most important lesson learned from the last comprehensive royalty review ordered by then-Premier Stelmach in 2007 is the need for governments to remain competitive with other jurisdictions when seeking to attract investment dollars. The response to increased royalty rates at that time was a significant erosion of capital investment in Alberta, which instead found its way to Saskatchewan, British Columbia and a number of U.S. states, including North Dakota, Montana, Wyoming and Texas. Premier Stelmach responded with a “competitiveness review” in 2010 and reacted to B.C.’s successful use of royalty credits and incentivization of new production technologies by introducing the Emerging Resources Technologies Program and the Natural Gas Deep Drilling Program. These initiatives were, in many cases, too late to halt the flow of investment already making its way to other jurisdictions.

Despite campaigning on the supposition that Albertans were not receiving their fair share, the Notley government appears to better appreciate the role Alberta’s royalty regime plays in competing for investment dollars. In evaluating Alberta’s competitiveness against other jurisdictions, the Panel engaged Wood Mackenzie to conduct a review of 22 comparable jurisdictions across the world, taking into account all elements of competitiveness, including resource quality, costs, well types and royalty rates. Wood Mackenzie’s report found that Albertans are currently being appropriately compensated for the production and sale of their resources, but that Alberta was less attractive for investment when compared to other jurisdictions inside and outside of Canada.

Alberta’s existing royalty regime takes prices and production levels into account to calculate the royalty rate for a specific well. All else being equal, a well with higher production per day pays a higher royalty percentage than a well with lower production, which negatively affects companies pursuing unconventional plays often characterized by higher initial production and a steeper decline rate. Companies pursuing such activities are important drivers and adopters of innovative and enhanced production methods, so the elimination of the production component of the royalty formula (except for mature wells that have very low production rates) may also be well received. After the pre-payout period and before a well reaches “Mature Well Status” under the new royalty framework, a well’s royalty rate will vary based only on changes to commodity prices.

The Emerging Resources Technologies Program and the Natural Gas Deep Drilling Program will be replaced by a flat 5% royalty until normalized well costs are recovered. This simple approach, which affords some return of capital prior to escalating royalty rates, improves industry’s ability to achieve a return on investment, a critical component of any investment decision, and is intended to stimulate adoption of innovative production technologies to realize lower production costs. The existing royalty regime has the unintended consequence of incentivizing operators to drill several less efficient wells to take advantage of fixed royalty holidays on each well and lower royalty rates due to lower production. Under the modernized royalty framework, operators are incented to drill regardless of the expected rate of production, creating more predictable payout periods and efficiencies that could enhance the province’s current competitiveness.

In an attempt to promote economic diversity and encourage more investment in Alberta, the Panel also considered diversification opportunities such as oil refining and upgrading in the province, and further development of the petrochemical industry in Alberta,[2] but did not provide any detail. The Panel recommended that the government undertake to develop a value-added natural gas strategy in Alberta and to evaluate the potential for partial upgrading of bitumen in the province.

The new royalty framework is designed to achieve economic neutrality (i.e., result in similar rates of return) with the existing framework. While the new framework is unlikely to evoke much negative reaction, given the number of important details yet to be released and the continued impact of low commodity prices on development, it remains to be seen whether the new royalty framework will achieve the desired balance between incentivizing investment, generating revenues for the government and promoting efficient development of the province’s resources. For now, the report at least gives comfort to the province’s principal industry that the strategy guiding those details recognizes some of industry’s current challenges and is intended to create opportunities for value creation rather than diminish them.

[1] Daily Oil Bulletin, “Royalty Review Will Not Increase Producer Costs ‘In the Near Future’, Notley Promises,” by Elsie Ross, January 13, 2016.

[2] Calgary Herald, “Alberta Eyes Value-Added Jobs; PetroChemical Firms Say Royalty Review Could Lure Billions in Investment,” by Chris Varcoe, January 18, 2016.

Courtesy of Osler. View original article here.