Late last year the Wall Street Journal reported that Brazil received US$1.88 billion in signing bonuses for six exploration blocks during a process of competitive auctioning. Chad in 2001 received US$25 million in a signing bonus for sour crude oil with lower viscosity compared with Guyana’s high quality sweet crude. Signing bonuses are also paid by shale oil producers to land owners.
There appears to be no universal methodology for determining the fair value of the bonus. It all depends on the negotiating demands of the lessor versus the oil company, and as in the case of Brazil, the desirability of what’s being auctioned. In general, the shale oil producers pay a certain dollar amount per acre, which can range from US$25 to US$5000 per acre. There are various idiosyncratic factors that can affect the per acre bonus payment. However, there are some general economic principles applicable as much to shale as to offshore drilling. These include risk variables such as a radical change in regulation, nationalization and regional conflict. The marginal cost of production, the time taken to recoup ExxonMobil and Hess’s initial investment, and the average cost thereafter can also determine the size of the signing bonus. Finally, the expected or long-term market price must also be taken into account.
Mr Christopher Ram noted recently, when he discussed the stability agreement of the contract with the ExxonMobil subsidiaries, the Guyana constitution and the Investment Act provide ample security against the risk of nationalization. There is also no major regional conflict in the offshore waters or in the Caribbean. Moreover, ExxonMobil understands the potential risk Venezuela presents and decided it is worth taking on. The Washington Post noted that the decision to invest and fast track the production offshore of Guyana has to do with the politics of getting back at the Venezuelan left-wing government as much as the very sound economics of the project, which carries a lower development cost than shale assets. The fact that Guyana’s offshore oil presents a lower average development cost compared with the best shale prospects was revealed towards the end of 2017, so we cannot hold this one against the negotiating team of 2016, unless the Minister knew the numbers as early as late 2015 before the public.
Furthermore, Trinidad and Tobago has just over 100 years of experience in oil and gas production, thus presenting a reliable source of talent and services, as well as the easy access to the Region from Texas. The Stabroek block is very close to TT and ExxonMobil can potentially do refining there (as an aside, in the spirit of Caricom unity, Guyana and TT might enter a joint refining agreement to get a share of the value-added benefits remain within the Region). In addition, the Stabroek block is also very close to American refineries in Texas and Louisiana. These geographical advantages will save ExxonMobil a substantial amount in transportation costs and reduce the risk of exploration, development and production. It should be no surprise, then, why Hess is selling out high average cost assets and deploying finance and physical capital into Guyana.
Shale leases are typically for 3 to 5 years and are susceptible to a faster depletion rate than offshore oil wells. As early as 2008, land owners in Ohio were receiving an average of around US$2500 per acre signing bonus. The Stabroek block is 6.6 million acres or 26.8 million square kilometers, which offers a production period of at least 22 years once the discovery is of a large enough quantity. It is obvious the fair value signing bonus that Guyana should have received cannot be obtained from simply multiplying US$2500 by 6.6 million, as they do in the shale oil sector. The methodology I am proposing would take into consideration two other important factors given the time dimension of offshore oil.
First, ExxonMobil spent an enormous amount of money to explore for oil and develop the production platform. If we take into consideration the publicly available data, and those from the IMF report, we would see the cost of exploration and development from 2015 to 2020 running over US$5 billion.
Second, we have a time value of money problem with the exploration costs occurring from 2015 to after 2020 given the “unrisk exploration upside” to use industry lingo. Moreover, given the size of the Stabroek block, we can expect explorations and new developments after 2020, thereby incurring added costs for ExxonMobil. As with all time value problems, we need a suitable discount rate to find the present value of explorations and development as at 2015-16 when the Guyana government negotiated the updated production sharing agreement. The discount rate can be the risk-free rate of interest plus some opportunity cost associated with ExxonMobil’s next best explorations in some other part of the world. It should be noted, the ring-fencing of cost is not necessarily applicable here when determining the fair value of the bonus, but it is most relevant to determining the true average cost during the production stage.
Given my calculation, a signing bonus of around US$238 million seems appropriate. This value imagines that I am in the latter months of 2015 to put myself in the shoes of the negotiators. If we consider new information released since November of 2017, the bonus is much higher. This amount of money can build a fantastic bridge across the Demerara River, freeing up funds which will be borrowed for the new bridge. In coming up with the number, I try not to be unreasonable so as to adversely affect the publicly available internal rate of return of the project. One other methodology that Guyana could have used, instead of the one I have here, is to consider a percentage of the present value of expected revenues projected.
Unfortunately, it does not appear that financial economists and managerial accountants were on the government’s negotiating team. These kinds of problems are not only legal and geological in nature, but also economic. As a matter of fact, it appears as though the Guyana government does not even know – under some reasonable assumptions – what’s the net present value of the project or the present value of all revenues. The government relies on the IMF and IDB, which no doubt have some fine technicians outside of the macroeconomics of developing countries. However, unless you can get the IMF and IDB people in the negotiating room, their help is limited. Moreover, having access to the IMF or IDB is no excuse for not having this kind of multidisciplinary capacity in government on a daily basis. In a sense, the sacrifice to date of failing to have a multidisciplinary and more diverse team in government is that bridge across the Demerara River!
It is also important for the University of Guyana to urgently boost training in fields like financial economics with relevance to emerging and developing countries. UG is beginning to appear more like a jobs training centre – a role reserved for the Government Technical Institute – similar to for-profit University of Phoenix and Nova Southeastern. The for-profit schools are not known for providing training in fields that promote critical thinking.
In the next few columns, we would examine whether Guyana can escape the resource curse.
