On February 16, 2007, Lyle Oberg, Alberta's Finance Minister, announced the appointment of a six-member panel of experts to complete a review of Alberta's royalty and tax regimes with the goal of ensuring Albertans are receiving a fair share from energy development through royalties, taxes and fees. The Royalty Review Panel (the Panel), which was put in place to fulfill a promise made by Premier Ed Stelmach during the 2006 Progressive Conservative leadership campaign, included independent experts in resource taxation and the royalty system.
The Panel's review focused on all aspects of the oil and gas royalty system, including royalties with respect to oil sands, conventional oil and natural gas. Among the issues the Panel was asked to address were whether the Alberta royalty system is sufficiently sensitive to market conditions and whether the existing revenue minus cost system for oil sands royalties is appropriate given current industry activity.
Royalty review report
The Panel released its report, entitled "Our Fair Share - Report of the Alberta Royalty Review Panel", on September 18, 2007 (the Report). The Report's general conclusion was that Albertans do not receive their fair share from energy development and that the existing royalty system, which differentiates between conventional oil, natural gas (including coalbed methane) and oil sands, should be modified.
The following summarizes the discussion contained within, and conclusions expressed in, the Report:
Conventional oil and natural gas
Royalty rates for conventional oil and for natural gas currently depend on a number of factors, including when the oil or natural gas pool was discovered. Generally, royalty rates for newly discovered pools are lower than royalty rates for older pools. The amount of royalties is calculated on each individual well and is based on the quantity of oil or natural gas produced from the well, the vintage of the pool that the well produces from, the market price of the oil or natural gas and the cost of processing the Government's royalty share of the applicable commodity. Above certain market prices, the royalty rates remain constant.
Under the existing royalty system, natural gas royalty rates start at 15% of production and increase as market prices increase to a maximum of 30% of production for newer pools and 35% of production for older pools after the market price reaches $3.60 per gigajoule. Adjustments for low producing wells can reduce royalty rates to 5%. Royalties for natural gas byproducts are related to the market price of those byproducts and can range from 15% to 50%. For conventional oil, the average royalty rate in 2005 was about 15%, with lower royalty rates applying to many wells in the Province. The maximum royalty rate is dependent on the vintage of the oil pool.
The Panel has recommended a simplified royalty system for conventional oil and for natural gas. Among the recommendations of the Panel are the following:
- the tiers of royalties based on year of discovery of the pool should be eliminated;
- the caps on royalty rates for natural gas and conventional oil should be raised to $17.50/MMBtu and $120/barrel, respectively;
- the price-sensitive royalty rate and the quantity-sensitive royalty rate should become separate elements within a single formula with the maximum total royalty payable being 50% of production;
- producers within "Township 53", an area classified many years ago as "oil sands" for administrative purposes, should no longer be able to elect to have their conventional oil wells administered under the oil sands royalty regime;
- the royalty formula for conventional oil should apply to propane, butanes and pentanes plus; and
- all incentive programs, including the incentives to drill deep gas wells, should be eliminated.
Collectively, the Panel's recommendations provide for an increase in the total Government take from conventional oil revenues from 44% to 49% and an increase in the total Government take from natural gas revenues from 58% to 63%. The total Government take includes royalties and all applicable provincial and federal taxes.
The current royalty system for oil sands production is a generic system established in 1997 to encourage investment and development of the oil sands. A royalty rate of 1% of the project's gross revenue currently applies for the period up to payout - when the developer has made profit equal to the capital invested in the project plus an allowance equal to the long term government bond interest rate, to recognize financing costs during the construction period. The royalty rate after payout is currently the greater of:
- 25% of the project's net revenue (gross revenue minus allowable costs), and
- 1% of the project's gross revenue.
While the royalty rate is a flat rate, the rate is price sensitive as it adjusts with profits which are correlated with oil prices.
The Panel concluded that the base royalty rate of 1% for the pre-payout period is still appropriate; however, the net royalty rate after payout should be increased to 33% from 25% and the base royalty rate should be payable in addition to the net royalty rate after payout.
One of the most significant changes recommended by the Panel is the introduction of an Oil Sands Severance Tax (OSST). The OSST would be a tax levied against gross revenues from bitumen production. The OSST rate would be linked to the price of West Texas Intermediate (WTI) crude oil in Canadian dollars with the rate being zero for WTI prices of less than $40/barrel, growing by 0.1% for each $1/barrel increase thereafter and reaching a maximum of 9% at $120/barrel. The Panel recommended that the OSST payments should not be considered allowable costs for purposes of calculating the net royalty payable after payout or for calculating net income for corporate income tax purposes.
Several other recommendations were put forth by the Panel relating to the classification of oil sands projects, the elimination of the provincial component of the accelerated capital cost allowance provided for in the federal Income Tax Act, the introduction of upgrader royalty credits and the evolution of a bitumen pricing methodology.
Collectively, the Panel's recommendations would provide for an increase in the total government take from oil sands revenues to 64% from 47%.
Additional general recommendations of the Panel that are noteworthy are the recommendation against grandfathering and the establishment of an accountability program. Consequently, if adopted, all recommendations would apply equally to all participants at the same time. As well, the Panel suggested the government implement a means to both assess the effectiveness of the revenue policy on an ongoing basis and to collect royalties associated with energy resources in Alberta.
The Premier of Alberta addressed the Province on October 25, 2007 and released the "New Royalty Framework" at that time (the Framework). The Framework outlines the details of Alberta's new royalty regime and sets out the following three guiding principles in the government's decision-making process:
- to support sustainable economic development that contributes to a high quality of life for all Albertans now and into the future,
- to support a fair, predictable and transparent royalty regime, and
- to align Alberta's royalty system with overall Government objectives.
The following summarizes the changes to the existing royalty system set out in the Framework:
Conventional oil and natural gas
The Government decided to adopt the recommendations of the Panel for conventional oil royalties, subject to a few modifications. Royalties are to be set by a single sliding rate formula and will be calculated on monthly production, as is currently the practice. Royalty rates will range from 0% to 50% depending on the market price of oil with a rate cap of $120/barrel. In addition, as recommended by the Panel, the Government will eliminate the system of tiers that distinguished vintages based on the discovery date of the oil pool and will eliminate several special oil-related royalty programs.
The Government has recommended similar changes to the existing royalty system for natural gas. Royalty rates for natural gas will now range from 5% to 50% depending on the market price of natural gas with a rate cap of $16.59 per gigajoule. The Government will also eliminate the tiers that distinguished vintages based on the discovery date of the gas pool.
Of particular significance is the Framework's departure from the Panel's recommendation to eliminate all incentive programs relating to the production of conventional natural gas. The Government will retain the Otherwise Flared Solution Gas Royalty Waiver Program and will extend this program to bitumen wells. In addition, the Government has agreed to revamp the Deep Gas Drilling Program rather than eliminate it. Support for this program is thought to be crucial for the viability of deep gas drilling projects in the Province. There is still some uncertainty about the intended changes to this deep gas incentive program and we hope that the Government will provide further details in the near future.
The Government will establish facility effective royalty rates to calculate the Government's share of capital for gas processing facilities. This is expected to improve the link of capital costs for natural gas to a particular facility within the Province.
Further, royalty rates for natural gas liquids will be modified and set at 40% for pentanes, and 30% for butane and propane. The royalty rate for ethane will not change and it will continue to be treated as natural gas.
The Government decided not to accept the Panel's recommendation to charge an OSST. The Government feels the proposed OSST is a tax to meet revenue needs whereas the royalty system is based on ownership rights. Instead, the Government will introduce a price sensitive base royalty rate for oil sands production. Under the new system, the base rate (pre-payout) will start at 1% and will increase for every dollar that oil is priced above $55/barrel, to a maximum of 9% when oil hits $120/barrel. The net royalty payable post payout will start at 25% and will increase for every dollar oil is priced above $55/barrel, to a maximum of 40% when oil hits $120/barrel. It is unclear whether the Government intends to keep the existing post-payout mechanism whereby the producer pays the greater of the base rate based on gross revenues and the net royalty rate based on net revenues.
The Panel's recommendation to implement a 5% upgrader royalty credit was rejected. The Government has decided to look at other methods of encouraging value-added activity in the Province, including taking its royalty share in kind to supply potential upgraders and refineries in Alberta.
In addition to the above system, the Government will eliminate its part of the accelerated capital cost allowance for oil sands projects. As well, "Township 53" projects will continue to have the choice of being subject to the oil sands royalty regime. Finally, the Government has committed to the implementation of a generic bitumen valuation methodology by June 30, 2008 to be used to value non-arm's length transactions.
The Panel's recommendation for further accountability has led to the initiation of a review to improve the systems and structures used to collect, verify and report royalty revenues received by the Province. This review is to be completed by March 31, 2008.
Collectively, the changes to Alberta's royalty regime are estimated to increase royalty revenue by $1.4 billion in 2010, which amounts to a 20% increase in revenues forecast for that year under the current regime.
The new royalty regime will take effect in January 2009. Significant changes will need to be made to numerous pieces of legislation including the Mines and Minerals Act, the Petroleum Royalty Regulation, the Oil Sands Royalty Regulation and the Natural Gas Royalty Regulation. The Government agreed with the Panel's recommendation not to grandfather existing oil sands projects. The Government is currently in discussions with Syncrude and Suncor, whose agreements expire in 2016, to participate in the new oil sands royalty system. The legal, economic and political implications of opening up these agreements for renegotiation will have to be considered by the Government and other interested parties.
The response from the oil and gas industry to the Panel's Report was overwhelming and universally negative. Among the complaints were that the Panel's conclusions were premised on unrealistically low capital cost estimates, particularly for oil sands development and deep gas drilling projects. Large industry participants had stated there will be severe declines in exploration and development expenditures in the Province if the recommendations of the Panel were fully adopted, thus weakening the Alberta economy and offsetting the increase in royalty revenues for the Province that the Panel estimated will be generated through the implementation of the recommendations in total.
The response from the oil and gas industry to the Framework are muted compared to the response to the Panel's Report, but it still appears to be negative. Most large industry participants have yet to fully comment on the Framework. However, it is anticipated that there will be a decrease in the level of drilling activity in Alberta in the upcoming drilling season as a consequence of the Framework as industry participants work through the impact of the Framework to gain a better understanding of the increased costs to them.
The Premier's stated goal was to meet the objectives of the Report. Although the Panel's recommendations were not adopted in full, there is no doubt the Framework will have a significant impact on the economy in Alberta and Alberta's share of future oil and gas royalties. The extent of this impact has yet to be determined.