This is the second 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 three weeks to digest the Royalty Review Report (the "Report"), commissioned by Alberta's NDP 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.
To read our full summary on the Royalty Review Advisory Panel's please see Alberta's New Royalty Framework – Same Idea, New Structure? (the "Royalty Review Post")
How might oilfield service companies be affected by the recommendations?
As discussed in our prior blog post Thoughts from the Trenches: Incentivizing Producers, the Recommendations incentivize cost-efficient producers and penalize high-cost producers generally, as well as those who incur cost overruns or drilling obstacles. We expect these incentives and penalties to present opportunities, as well as difficulties, for those companies serving the upstream oil and gas industry.
We expect that large producers are better equipped to manage the fallout from the Recommendations and that small producers may be disincentivised from drilling new wells at all. Competition amongst oilfield service companies for drilling and service contracts with large producers should intensify as a result.
For drillers like producers, bigger will be better – now more than ever.
The Recommendations will likely result in intensified competition amongst oilfield service providers for mandates from large producers and these mandates will inevitably favour the larger drilling companies. Not only will producers be interested in reducing their in-house G&A, thereby favouring reductions in the number of external contractors, but economies of scale will allow larger service companies to cut costs and cut prices. Lower prices will be necessary to secure mandates from large producers, with quantity of wells drilled becoming increasingly important as the Recommendations effectively squeeze service industry margins. We believe that smaller service companies will be challenged to compete on price and will, as a result, feel pressure to consolidate.
Fixed cost contracts could become the new normal for drillers.
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. 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.
As drilling companies compete for mandates from large producers (due to their large quantity of work), we expect that competition amongst service providers will result in large producers insisting on fixed cost contracts, with pricing expressed as a proportion of C-Star. 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, for example, 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.
Smaller producers will have difficulty retaining large drilling companies for relatively small projects. While we expect that larger producers will effectively never pay greater than 100% of C-Star for a well, smaller producers could very well be forced to do so in order to secure the attention and service of a drilling company. Without the requisite quantity of wells to drill, smaller producers may be deemed significantly less important to service companies that will be focussed on their new bread and butter – delivering low-cost performance to larger producers. Smaller producers will experience relatively higher drilling costs as a result, leading us to expect increased consolidation of small producers and small drilling companies alike as a result of the Recommendations.
Net Present Problems? - Reserves Engineers' Job Just Got Harder.
Just as service companies will be driven to compete for work from the largest producers, we expect reserves engineers to be no different. Consolidation will mean less small producers, and reserves engineers will be operating in the same cost-sensitive and hyper-competitive environment as all other service providers. There's just one difference – their job will also get a lot harder.
The form of reserves report required under Canadian securities laws may be adjusted as a result of the Recommendations, given that Alberta is home to the majority of Canadian oil and gas activity and the Recommendations represent a marked departure from past practice particularly as royalties will relate to calculations of the net present value of future net revenues ("NPV") from oil and gas reserves. While we could only speculate as to the form of these new requirements at this time, reserves engineers would be tasked with compliance.
The process of predicting NPV has and will become seemingly more difficult due to the Recommendations. NPV calculations consider the impact of royalties and, as discussed in the Royalty Review Post, the price function formula for post-payout royalty rates is to be finalized with specific formulas no later than March 31, 2016. The Alberta Government will be creating an internal team of experts that will be monitoring the new royalty framework and the oil and gas industry's costs and prices. This review team will ensure that the royalty rates framework adapts to provide consistency for the industry.
For now, future royalty rates are unknown, making NPV calculations functionally impossible pending the announcement of the price function formulation for post-payout royalty rates. Further, any variability in the post-payout royalty rates will render NPV calculations relatively more contingent and unreliable. Pre-Report NPV figures will also not be meaningful for comparative purposes as against post-Report NPV figures.
BLG will be following the development of the post-payout royalty rates by the Alberta Government's review team and will provide analysis of those rates once announced.
In our next post, we will discuss our views on the future of financing for the oil and gas industry in Alberta.
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