On January 29, 2016, the Alberta Government announced publicly that it would adopt the recommendations of the Royalty Review Advisory Panel, presented in the Alberta at a Crossroads, Royalty Review Advisory Panel Report. The panel’s task was to “identify opportunities to optimize Alberta’s royalty framework” with a focus on optimizing the returns to Albertans while maintaining industry competitiveness, encouraging diversification and innovation in our province and supporting responsible resource development. The panel’s review of the current royalty framework identified a lack of adaptability over time, distortions related to product type, incentive for less efficient development and a lack of transparency on costs included in the “revenue minus costs” oil sands royalty structure. More pointedly, the panel found that, first, Albertans have been receiving a fair share – Albertans’ take is about middle of the pack in terms of competitiveness – and, second, the Alberta oil and gas industry cost structure is high. The panel’s royalty framework recommendations stem from these findings, with oil sands royalties materially unchanged and crude oil, liquids and natural gas royalties modernized.
Let’s take a closer look at the MRF.
What We Know
It’s not that complicated.
- There is a transition period that mitigates the impact of a near term step change in royalties for both the industry and government. The MRF will apply to new wells starting in 2017, with existing royalties remaining in effect for 10 years for wells drilled beforehand.
- The MRF will be based on the “revenue minus costs” royalty structure consistent with the global standard. In this context, costs refer specifically to capital costs and do not include operating costs. Notably, the proposed structure provides an incentive for industry participants to lower their costs, while at the same time offering a greater take for Alberta as average industry costs improve. With learning and innovation, the cost distribution (see below) can be expected to shift to the left, and, as partners, industry and Albertans will share in the benefits.
Source: Alberta at a Crossroads, Royalty Review Advisory Panel Report
- Crude oil, liquids and natural gas royalties will be harmonized across product types with a view to mitigating royalty rate surprises and royalty revenue distortions.
- Incentives will be simplified. A flat royalty rate of 5% will apply pre-payout, with higher royalty rates that increase with commodity price post-payout.
- Payout will occur when cumulative revenues from a well equal the well’s Drilling and Completion Cost Allowance, C* (pronounced “C-star”)
Source: Alberta at a Crossroads, Royalty Review Advisory Panel Report
- A well’s C* is an easy one time calculation, performed once a well is drilled and producing. It is based on vertical depth and horizontal length using the following simple formula:
C* = a1 × (TVD) + a2 × (TVD – Vdeep) + a3 × (TVD × TLL)
- TVD is true vertical depth of the well
- Vdeep is the vertical depth threshold applicable to all wells, beyond which a well begins to receive additional capital cost allocation
- TLL is the Total Lateral Length
- a1 is a capital cost allocation for every meter drilled vertically
- a2 is a capital cost allocation for every meter drilled deeper than Vdeep
- a3 is a capital cost allocation for every meter drilled horizontally, for every meter drilled vertically
The C* formula will be reviewed by Alberta Energy and an expert committee using independent statistical depth and cost data every 3 to 5 years, to ensure that C* remains representative. Strategic programs can also be structured around C*.
- Each year, C* will be calibrated to an Alberta Capital Cost Index, ACCI, to reflect current average costs. Industry participants will be obliged to report actual capital costs to the Alberta Energy Regulator to be used to calculate the ACCI for the subsequent year. ACCI year-over-year changes, to be instituted by Alberta Energy, will be limited to a maximum of plus or minus 5% and published in conjunction with an Annual Report each year.
- Post-payout, once production falls below the maturity threshold (a bopd or Mcfpd threshold), the well will be classified as mature and royalty rates will be reduced linearly in proportion to production down to a minimum royalty rate of 5%.
- Returns to industry and Albertans’ share of value received will, in general, be targeted to remain unchanged, with the understanding that current incentive programs are not well designed at commodity price extremes.
- The recommendations are based upon what is now a defined set of guiding principles, criteria that can be used to assess and evolve the MRF over the longer term.
What We Don’t Know
While the devil may not, in this instance, be hidden in the details, certain details remain unknown.
- Formulaic inputs including a1, a2, a3 and Vdeep that drive C* determination.
- The practical definition for TLL. Is this measured depth minus TVD?
- The commodity price-royalty rate transforms, or price functions, that will determine post-payout royalty rates for crude oil and natural gas, noting that the price function for other hydrocarbon liquids will be the same as that calibrated for crude oil.
- Gas cost allowance: will this program be retained but simplified and/or optimized?
- The hydrocarbon maturity thresholds for crude oil and natural gas, initially estimated at 20 bopd or less and 200 Mcfpd or less, respectively.
- The practical criteria for qualifying a well as mature.
- The development of a special application process for special allowances to address exceptional situations.
- The development of strategic policy overlays, specifically including enhanced hydrocarbon recovery and high-risk experimental wells, through adjustment to C* or the allocation of a special C*.
- The development of a strategy for industry and Albertans to share the impact of carbon levies by incorporating allowances in the MRF (C*, reference prices and/or the price function), pending more information on Alberta’s Climate Leadership Plan.
- The clarification of royalty framework details for new wells drilled before the MRF implementation date in 2017.
- And, importantly, resultant resource play impacts. Although targeting an overall net neutral framework, there will be winners and losers.
Calibration is now underway to finalize formulas and establish procedures along with the specific timeline for implementation, with the release of these details anticipated by March 31, 2016.
The author of this post is Caralyn Bennett, P.Eng. Ms. Bennett is Vice President, Corporate Strategy at GLJ Petroleum Consultants
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