Recent discussions surrounding the cost recovery provision in the oil contract and the possible renegotiation served as motivation for this column. I intend to clarify and reemphasise several points I made on these topics in previous columns. Over the years, I have examined various topics which are still relevant to present deliberations. These include the oil and gas contract, recurring flooding, the gold sector, the sugar industry, constitutional and electoral reforms, income and wealth distribution, economic development policies, finance and development banking, inflation, the foreign exchange market and several others.
Relating to the oil contract, the first point to note is: calculation of the profit ExxonMobil (and partners) make, as well as the share of said profit which is paid to Guyana depends on knowing the unit (or average) cost of producing a barrel of oil. Various unit cost numbers have been given during press conferences of the oil companies; however, the long-term unit cost per oil project (Liza 1, Liza 2, Payara, Yellowtail and future ones) remains uncertain. A major oversight occurred when the original negotiators of the previous administration failed to pin down a long-term average cost per project. I use “long-term” to emphasise that the recovery of per-project fixed costs (except administration cost) must come to an end and the true unit cost would kick in. At the true unit cost, Guyana’s share of profit jumps to approximately 37% in each year (see my column: “The crafty contract and Guyana’s implicit and explicit earnings”, April 1, 2018).
In the absence of a long-term average cost, we have a legalistic determination of this very important cost variable. The legalistic unit cost derives from the 75% of total revenue that can be applied towards the recovery of fixed cost in a given year. In other words, the oil companies are allowed, as per the contract, to apply up to 75% of total revenue earned in a given year towards recovering previously incurred fixed costs. It does not mean that the total outstanding fixed costs (exploration, administration and other fixed costs) are recoverable in one year. Without ring fencing, the recovery of the fixed cost would be applied for many future periods – hence, reducing the market value of the profit oil and Guyana’s share.
Furthermore, the 75% fixed cost recovery cap does not mean that ExxonMobil and partners do not achieve 100% cost recovery; they just don’t achieve the 100% recovery in a single year. As a matter of fact, if we do not know the true long-term average cost, mathematically it is possible that the oil companies will recover more than 100% of their total fixed costs; and rest assured the lawyers and transfer pricing accountants will make this possible. If the American taxing agency, Internal Revenue Service, cannot get its own multinationals to pay their fair share of profit-based tax, then Guyanese activists face the impossible task of obtaining the true measure of the market value of profit oil.
For these reasons, I mentioned a single tweak to the oil contract if renegotiation is the objective. The tweak is based on the universal financial intuition which says that a dollar received today is always greater than a dollar earned next year, the year after next, and so on. This single adjustment will realise billions of extra dollars for Guyana. Whether the government will spend the extra billions wisely is a subject for many columns. The unintended consequences of the unprecedented oil foreign exchange windfall – even without contract renegotiation – are yet to be fully anticipated. For example, we do not have a sense of monetary policy transparency in place for dealing with the massive government budgets and oil-induced investments.
The single tweak I propose relates to reducing the yearly cost recovery cap from 75% to 50%. It means that in any given year, the oil companies can apply 50% of total revenues towards cost recovery. Let us consider what this means under a regime of binding cost recovery, meaning that the 75% is binding in the sense that the oil companies take full advantage in recovering fixed costs. And also consider a system when 50% cost recovery is binding. In the latter case, 50% of total revenue can be applied to cost recovery in a given year. The implication of the latter is Guyana gets a larger amount of cash up front.
What does this mean for the upfront oil windfall for the Guyana? As I have explained in previous columns under the assumption of full cost recovery, Guyana receives 14.5% of a barrel of oil; algebraically this is expressed as 0.145P (where P = the market price for a barrel of oil). Also, as I have previously argued, if the 2% royalty is billed as a partial cost recovery, Guyana gets 13.5% of each barrel or algebraically 0.135P. Therefore, this formula is general and all the analyst needs to do is multiply 0.145 (or if they prefer 0.135) by the existing market price and quantity produced (barrels per day) to obtain the share of profit and royalty going into the Natural Resource Fund.
Let us now work out the formula when there is a 50% binding cost recovery cap. Doing so requires remembering that unit profit is equal to unit revenue minus unit cost. Since we do not know the true unit cost, we must substitute cost = 0.5P. This results in the expression 0.27P, which is clearly greater than 0.145P. The implication here is no matter how many barrels per day are pumped at a given market price, Guyana always gets more money upfront given that 0.27P is greater than 0.145P.
Some might argue that reducing the cost recovery cap will mean Exxon takes longer to recover their fixed costs and as such reduces the lifetime amount of funds Guyana gets. However, that view is incorrect for two reasons. Firstly, we will never know the true unit cost of production because of transfer pricing and tax avoidance. Secondly, in present value terms, Guyana gets almost twice as much money at a 50% cap.
I ran multiple simulations of present value. The results will hold in any deterministic scenario given that 0.27P is greater than 0.145P. Let us take a look at one outcome where production is 500,000 barrels per day, the market price is US$65 per barrel, and the two cost-recovery algebraic expressions: 0.145P and 0.27P. Since we are now dealing with present values, a discount rate of 10% is chosen to reflect the risk-free interest rate and a reasonable economic growth rate that could be achieved by spending the extra oil funds.
Under the latter scenarios, when the cost recovery cap is 75%, Guyana gets US$15.5 billion in present value over a 20-year period. Under a cost recovery cap of 50%, Guyana gets US$28.4 billion in present value over the same 20-year period. Therefore, that single tweak in the contract will realise an extra US$12.9 billion in present value cash windfall over the 20-year project period. That’s not a small amount of extra foreign exchange for a country with serious infrastructure and climate change challenges.
If utilised properly, this extra foreign exchange can be deployed towards dealing with the recurring floods – much of which has been self-inflicted since 1992 because the new rentier class used political access to obtain coastal land. And maximising land space motivated the ahistorical post-1992 rentiers to cover up many canals. Prior to 1992, several key canals were covered up because of pure incompetence by the old PNC. Making the coastal plain habitable for another century will partly require taking back lands from the rentiers and reproducing canals that enslaved people dug and indentured labourers maintained.
Comments: tkhemraj@ncf.edu
