Sproule Associates Limited Summary of the Royalty Review Advisory Panel Report 1

Transcription

1 Sproule Associates Limited Summary of the Royalty Review Advisory Panel Report 1 February 1, 2016 Introduction On January 29, 2016 the Alberta Government adopted the recommendations proposed by the Royalty Review Advisory Panel ( the Panel ) in their report entitled ALBERTA AT A CROSSROADS ( the Report ), available at Sproule commends the panel for their dedication and extraordinary effort in finalizing their recommendations in the four months following the establishment of the Panel by the Government on August 28, The Panel consisted of four members: Dave Mowat, Chair President and CEO, ATB Financial Leona Hanson Mayor, Town of Beaverlodge, Alberta Peter Tertzakian Chief Energy Econonmist & Managing Director, ARC Financial Corp. Annette Trimbee President and Vice-Chancellor, University of Winnipeg The Panel s mandate, process and approach are well documented in the Report and it is Sproule s recommendation that all Albertans take time to read this document. It provides comprehensive insight into the oil and gas industry in the context of the Alberta economy and its competitive position relative to the rest of the world. 1 Disclaimer: This article has been prepared for informational purposes only and does not constitute advice or an opinion on any issue. The article was derived from the interpretation of public information obtained from various sources and is partially based on discussions with individuals involved with reserves evaluations. If you have questions or comments, or require additional details or advice about specific situations, please contact Sproule directly.

2 2 Preamble Sproule s focus in the following summary is our need to understand the new royalty costs associated with the development of hydrocarbons in Alberta. Royalties are a key component in the determination of value and as the year-end reporting of reserves and values is near completion, production companies have a vested interest in the implications of the recommendations. The recommendations put forward by the Panel will not impact the values estimated by Sproule for year-end reporting effective December 31, In accordance with guidance in the Canadian Oil and Gas Evaluation Handbook (COGEH), an evaluation is to incorporate information available up to and in effect prior to the effective date of the report. Nonetheless, the need to quantify the impact of the Modernized Royalty Framework ( MRF ) is critical and Sproule will be working to roll out sensitivity analyses as quickly as possible. The Report does not provide the specific coefficients necessary to derive royalty payable under the MRF. Calibration and publication of these specifics has a proposed release date of March 31, Within the Report there are recommendations for the development of the MRF that provide guidance for calibrating the royalty formulas. The MRF is to be calibrated using a sample set of representative wells from at least 40 plays across Alberta such that derivations of future profitability are on average, neutral. Perhaps a company with sufficiently diverse assets will achieve neutrality with the MRF relative to the existing royalty structure. Will the MRF achieve neutrality across all plays? Will there be neutrality for companies with expertise and focus in a single play? Is there neutrality across all price scenarios? For clear answers to these questions additional work is required on the part of the Calibration Team. Summary of Panel Recommendations Oil Sands Royalty Rates There will be no change to Oil Sands Royalty rates. The current post-payout rate is comparable to other international producing jurisdictions. Oil Sands Royalty Structure: Pre-Payout: Sliding scale between 1% and 9% based on gross revenue. Post-Payout: Sliding scale between 25% and 40% based on net revenue. The Panel recommends that the Province annually publish a financial summary of each oil sands project, including the following items: - Revenue - Diluent - Gross revenue net of diluents - Bitumen production - Capital costs - Return allowance - Net revenue - Royalty rate

3 3 - Gross revenue per barrel - Operating costs - Royalty dollars collected MRF for Oil and Natural Gas Wells For all wells drilled prior to January 1, 2017 the existing royalty framework will continue to apply, including incentives from the Natural Gas Deep Drilling Program. Royalties payable on these ( Old Wells ) will be based on the existing royalty structure for 10 years before converting to the MRF. All wells spudded after the implementation date of January 1, 2017 ( New Wells ) will be subject to royalties determined under the MRF. There will be one royalty structure for all wells regardless of whether they would be considered an oil well or a gas well. The Report outlines the concepts that will be implemented for New Wells; however, specific coefficients or price sensitive formulas have not been reported at this time. The magnitude of the components used in the royalty formulas and the actual royalty functions require calibration. The Calibration Team expects the Calibration Period to end March 31, The Natural Gas Deep Drilling Program will be extended to include wells drilled in 2016, with termination of benefits within 5 years (the end of 2021). The MRF is designed to implement unique royalty formulas for three distinct phases of production life. In general, the MRF is designed to provide a low royalty until payout, followed by a sharing of profits after payout, followed by a lessening of royalties at lower production levels to promote the extended life of wells. The current royalty system provides incentive programs with a low royalty until the incentives payout. The MRF retains the concept of low royalties in the early life of a well, but with an alternative program. The time to payout under the old system relative to the time to payout under the MRF is a comparative we are investigating. Preliminary research indicates a shift to shorter payout times under the MRF. 1. Early Life Flat royalty rate of 5%. The flat rate will remain in place until cumulative revenue generated from the well exceeds the Drilling and Completion Cost Allowance C*. This is called a Revenue Minus Cost (RMC) model. Operating costs are not included as a cost component. C* (pronounced C-star ) is determined based on a formula that considers the depth and length of the well drilled. C* will be unique for each well and will not change once the well is drilled and placed on production. It is recommended that the coefficients used in the determination of C* be calibrated every three to five years. Further, it is recommended that an Alberta Capital Cost Index (ACCI) be established and maintained to allow C* to float on an annual basis as industry costs change, with annual changes limited to plus or minus 5%. The ACCI would be announced on March 31 of each year for application effective April 1 of the same year. Companies will be obliged to report actual capital costs, along with other mandatory well

4 4 information, to the AER to be used as statistical inputs to calculate the ACCI. C* = a1*(tvd) + a2*(tvd-v deep ) + a3*(tvd*tll) Where: - TVD is the true vertical depth of the well; - V deep 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 vertical meter drilled deeper than V deep (current data suggests 2,000 to 2,500 meters); and - a3 is a capital cost allocation for every meter drilled horizontally, for every meter drilled vertically. Revenue is to be determined based on production volumes and commodity par prices published by Alberta Energy. 2. Mid Life Royalty rates will be determined using a new Price Function based on commodity prices for the various hydrocarbon streams. The Panel indicates that it will be similar to the current royalty framework, but notes that the current programs are not well designed for extraordinarily high or low prices. There will be independent price functions for crude oil and natural gas. Price functions for other hydrocarbon liquids will be the same as that calibrated for crude oil. 3. Late Life When hydrocarbon production drops below a certain rate, deemed the Maturity Threshold, the royalty rate will be adjusted downward in proportion to declining production rates. A minimum royalty rate of 5% is suggested. The Panel states that the maturity threshold has not yet been determined, but suggested that it be in the range of 20 barrels of oil per day or less for crude oil or 200 thousand cubic feet per day or less for natural gas. Strategic Programs for Oil and Natural Gas Development The Panel acknowledged the need for unique strategic programs in support of enhanced hydrocarbon recovery and high-risk experimental wells. They recommended Alberta Energy establish programs for these two areas by March 31, Gas Cost Allowance (GCA) There were no recommendations regarding GCA other than a comment that there may be opportunities to simplify and optimize some aspects of GCA.

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