This is the first of four blog posts in BLG’s Thoughts from the Trenches blog series on the Alberta Royalty Review Report.
Albertans, and more broadly oil and gas industry watchers, have had over two weeks to digest the Royalty Review Report (the “Report”), commissioned by the Notley government . The government commissioned the report to assess whether Albertans were receiving their “fair share” of royalties from hydrocarbons produced from Alberta Crown-owned subsurface lands, which comprise about 80% of Alberta’s mineral lands.
The government has accepted the Report’s recommendations (the “Recommendations”) in their entirety, so we expect implementation of new Crown royalties to begin shortly, as early as the summer, and no later than the end of 2016.
Here are some highlights:
- Royalties on oil sands, and royalties on wells drilled prior to December 2016, will not change.
- Effective January 1, 2017, royalties on new wells will be calculated using a “revenue minus deemed costs” model:
Each new well will be assigned a Drilling and Completion Cost Allowance (defined in the Report as “C*” or “C-Star”), based on the vertical depth and the horizontal length of each well. C-Star won’t be derived from actual drilling and completion cost from a specific well; instead it will be drawn from an industry-wide average of drilling and completion cost per metre of vertical depth or horizontal length of all the wells drilled in that year. The C-Star will be reset every year (within a 5% band per year) based on capital costs incurred industry-wide in the previous year. Conceptually, the C-Star is similar to a mill rate. It’s simply an amount derived from industry-wide data used to calculate a tax.
The C-Star will be used to calculate deemed payout– this is the date on which the government deems the well owner should have recovered its capital costs for drilling and completing the well, based on an industry-wide average. Before deemed payout, the Crown royalty will be 5% of gross revenue derived from the well’s production, irrespective of what hydrocarbon is produced. After payout, the royalty will be of an order of magnitude higher and will decline over time as well production declines. The suggested publication date for the after-payout royalty amount is March 31, 2016.
Once the well begins producing, the C-Star for that well will be set in stone, such that it will not be subject to annual reset.
To read our full summary on the Royalty Review Advisory Panel’s report check out Alberta’s New Royalty Framework – Same Idea, New Structure?
How might upstream producers be affected by the recommendations?
The Recommendations incentivize cost-efficient producers, and penalize high-cost producers generally, as well as those who incur cost overruns or drilling obstacles.
The Royalty Panel identified that Alberta’s upstream producers are, on average, high-cost producers. Capital and operating costs are higher in Alberta than in other comparable jurisdictions, and the Report specifically emphasized that high operating costs in Alberta are an “uncomfortable reality” for Alberta producers – effectively there’s no reason for well operating costs to be so high. The Report implies that Alberta producers were high-cost producers because commodity prices were high, and this allowed them to operate inefficiently while maintaining strong returns to investors.
The use of deemed payout, as opposed to actual payout, effectively incentivizes producers to keep costs low. Producers calculate actual capital cost recovery (i.e. actual payout) on a per-well basis – once actual capital costs have been recovered, the producer is in a profit environment (profit = gross revenue less royalties, operating costs and maintenance capital). As royalties increase upon deemed payout, the producer’s profit will decrease commensurately at deemed payout. Under the Recommendations, a producer is highly incentivized to have actual payout of a new well well occur before deemed payout – to “beat the average” in the language of the Report. Keeping costs lower than industry average allows producers to maximize profits in a low royalty environment – it’s a “kicker”.
On the other hand, high-cost producers will be penalized, and those who incur cost overruns during the drilling and completion process will be doubly penalized. If a producer’s capital costs for drilling and completion of a new well exceed the industry average, actual payout of the well occurs after deemed payout. As the occurrence of deemed payout raises the royalty rate significantly, actual payout would take that much longer to occur (potentially much longer), because post-royalty revenue, used to repay capital cost, would be reduced.
A vivid illustration of Alberta as a high cost environment has arisen in light of the recent collapse of commodity prices. This has led to significant job losses across the industry (many in head office), and while some of these losses are due to there being reduced capital budgets (no new wells being drilled means fewer people needed to drill those wells), many producers are reducing operating costs by simply reducing head count and requiring those remaining employees to do more. These cost-cutting measures are reflective of the Report’s findings but are also reflective of its goals – to make Alberta producers more efficient.
The effect of the Recomendations will be further exacerbated where there have been cost overruns or problems arising in the drilling program process. If a well is over budget, and also its costs exceed the C-Star costs, actual recovery of capital cost of the well will take even longer.
A producer incurs a minor blowout during the drilling process, notwithstanding that it is an efficient operator and the blowout could not have been foreseen. The blowout is contained, and the well begins producing. Damages caused by the blowout would in all likelihood be insured – however the well’s actual cost is significantly more than the industry average. As such, the C-Star for this well would be well below the actual cost of the well. This leads to deemed payout occurring before actual payout, rendering the well is less economic.
The Recommendations incentivize lower-risk and lower-cost new wells, unless the well is deep.
The C-Star contemplates that wells below a particular depth are more difficult to drill and would therefore have a different C-Star from more conventional wells. However, new wells having other significant costs – such as expensive surface access requirements or specialized drilling equipment – will be relatively more expensive, but would not receive the same royalty relief as a deep well.
Regulatory oversight, especially in the field, may have to be tightened.
The drive for a low-cost environment may have the unfortunate consequence that producers who cannot beat the average resort to cutting corners with respect to health, safety and the environment. It will be essential that the Recommendations are accompanied by strong enforcement of laws and regulations in the field.
Large producers are more well-equipped to manage the deemed payout environment, while small producers will have higher risks and rewards or penalties. This may disincentivize small producers from drilling new wells at all, and instead pushes them to focus on secondary recovery.
This prediction comes from simple math – a large producer (one with hundreds of wells under management) will operate some wells whose drilling and completion costs exceed the average and others that beat the average; therefore, on a corporate basis, a large producer will likely reflect the industry average. A small producer, by contrast, could benefit relatively significantly from a well whose actual payout occurs well before deemed payout as it would be generating post-capital recovery revenue in a low royalty environment and therefore its corporate return on investment could be conceivably much higher than under the current royalty structure. Woe betide the small producer who doesn’t beat the average, as its return on capital would be doubly delayed. This may push small producers to the lower-risk environment of secondary and tertiary recovery, where the royalty rate is already established.
The use of deemed payout may lead to fixed cost contracts for drilling and completion of a drilling program. The more wells that are part of the program, the lower the cost for the program would be.
One of the main uncertainties in capital allocation for upstream producers is drilling and completion cost for new wells. This uncertainty is now exacerbated by the Report’s proposals, as in addition to determining how much a well will actually cost to drill, producers must also determine whether wells can be drilled for less than the C-Star amount allocated to that well.
Accordingly, the Recommendations incentivize both producers and service companies to enter into fixed cost contracts for a number of new wells, similar to a turnkey construction contract. For example, if a producer committed to drilling 10 wells during a calendar year, the drilling company in return could agree that the total actual cost of drilling and completing those wells is a percentage of the C-Star cost (i.e. 95% of C-Star). In this way, the producer’s costs could be managed, and the service company would have an inventory of wells to drill.
Read more of BLG’s insightful blogs about the energy indsutry here