17 Nov The “Incentive” to increase oil production in Bolivia
Thanks to a previous post on Efficient Taxation, I have information about the Incentives Bill currently being discussed in the Bolivian Assembly (formerly Congress). For this reason, I would like to share my interpretation of this text.
As a preliminary note, I would like to mention that this Bill encompasses many exploration and production options, making it very difficult to condense them into a single post. Therefore, I will try to highlight the key points of the Bill and perhaps, once the regulatory Supreme Decree is made public, I can be more specific about other details.
Let’s begin. First, let me establish the general analytical framework. As usual, I will use some graphs that I hope will be illustrative. The following figure provides a general overview of how the “pie” of hydrocarbons is currently divided into exploration and production activities. 18% is allocated to the producing department and the General Treasury of the Nation (TGN); the Direct Hydrocarbon Tax (IDH) of 32% is shared among the Governorships, Municipalities, Universities, TGN, Indigenous Fund, etc.; an x% resulting from the so-called “Nationalization” process is allocated to YPFB, and a y% allows the private operator to cover its costs and obtain its corresponding profit.
In this context, the Bill proposes the creation of a Fund (whose acronym is FPIEEH) to finance an incentive for additional oil and condensate production in the future (we will see how this works). Specifically, this Fund is financed with 12% of the resources from the Direct Hydrocarbon Tax (IDH) starting in January 2016—yes, in just a couple of months. That is, something like this:
If my reading of Article 12 is correct, then all institutions receiving resources from the Direct Hydrocarbon Tax (IDH) must allocate 12% of those resources to the Fund in question. Now, who administers the Fund? What is the amount of these resources? According to Article 13, the resources of the Fund will be held in custody by the Central Bank of Bolivia (BCB) under the guidelines applied to international reserves (see the following figure). Furthermore, if the international oil price in 2016 is between 50 and 60 US$/barrel, the Fund’s resources could range between US$ 170 and 200 million for that period. Accumulated up to 2019, these resources could reach a figure between US$ 680 and 800 million.
Now let’s move on to the incentive. The core idea is that an operator (private or YPFB) can obtain a sum of money per unit of additional oil/condensate production. What do we mean by additional? According to the wording of the Bill, this “additional” production comes from new exploration investments (made before 2019) and/or production above a “baseline” relative to the current level. In short, all “new” production qualifies for this incentive.
Let’s consider an example of an oil field under current price conditions. Please, dear reader, pay attention to the following figure, where the incentive is shown in orange. Notice several things: 1) future production (thanks to the incentive) still pays royalties (blue), IDH (red), and “nationalization” (yellow) while also receiving an incentive (orange); 2) future production also contributes to the IDH Fund (not represented in the figure); and 3) these figures are per unit produced… don’t worry, I will explain this further below.
In this scheme, what if we add prices and values? See the next figure. Currently, the wellhead oil price is approximately US$ 25/barrel, of which US$ 12.5/barrel (4.5+7.0+1.0 in the graph) goes to the State for royalties and IDH. A small portion goes to YPFB for Nationalization (yellow section), and the rest to the field operator (green section). The new production also pays these taxes but receives the incentive in return. As you can see, the scale (the size of the rectangles) I used in the graphs was not random—I aimed to give an “order of magnitude” to the incentive. Simply put, the new production would pay the blue, red, and yellow rectangles in taxes but would receive an incentive equivalent to the orange rectangle (Article 6 states: “In the Traditional Zone, the incentive will be determined based on the international oil price, subject to regulation, and will have a minimum amount of US$ 30/bbl and a maximum of US$ 50/bbl”).
How does the State deliver this subsidy? The mechanism is quite complex, so I turn again to the next figure. The operator requests the incentive from YPFB; YPFB then submits the incentive request to the Ministry of Economy and Finance, which in turn seeks authorization from the Ministry of Hydrocarbons and Energy. Once authorized, the Ministry of Economy and Finance issues Tax Credit Notes (NOCRES) using the Fund’s resources. These NOCRES are sent to YPFB, which then transfers them to the operator. There is no doubt that this is complex institutional engineering that must be set in motion.
Now, let’s move on to some questions that arise from this scheme:
Question 1: What happens when the fields in question belong to different producing departments? That is, something like what is shown in the next figure. Imagine that Department “A” allocates IDH resources to create the Fund, but the exploratory activities were carried out in Department “B.” As a result, Department “A” would not benefit (as expected) from the harvest of this new investment. Will there be any provisions for this?
Question 2: Is it possible to “secure” the Fund’s resources? The reader will recall that in a previous paragraph, I calculated how much the Fund could receive by 2019. Why did I do this? Because the Bill mentions that this incentive will be granted to investments made before 2019. This, coupled with the fact that exploration periods last between 5 to 7 years, suggests that the first years of the Fund will be for “accumulation,” and after 4 or 5 years, there will be a “depletion” period. This mechanism works if the Fund’s resources are managed prudently.
Question 3: Is it possible to regulate those contributions to the Fund be made only under reasonable international oil price conditions? My very personal opinion is that a mechanism of this nature should have been applied during the “fat cow” years, not now that prices are low. Those receiving IDH funds will not only see their resources reduced by lower prices but also by this 12% contribution. In this sense, it might be wise to establish that 12% contributions to the Fund are made only when the international oil price exceeds a certain threshold.
I believe the administration of this mechanism will be a nightmare (as my good friend from Santa Cruz would say… a true “Macedonia”), and frankly, I do not think it fully resolves the fundamental problems of the hydrocarbon sector in our country. I believe it is time to discuss a new Hydrocarbon Law that allows for progressive and efficient tax rates, clear rules to attract investment, the gradual elimination of subsidies, the corporatization of YPFB, opening new markets, promoting exploration in non-traditional areas, honestly discussing the relationship with the environment and indigenous communities, sector information, etc. In other words, I think it is time to move beyond words and take comprehensive action.
I do not doubt that this Incentives Bill has been the result of long hours of discussion and analysis within the Executive Branch, but always within the usual political constraints… and it shows. I understand that it is difficult to separate politics, especially partisan politics, from the hydrocarbons debate in a country like ours. However, the data… those stubborn data (as my good friend Milton would say) on reserves, prices, costs, production, and markets bring us closer to a reality that cries out for a genuine national commitment.
S. Mauricio Medinaceli Monrroy
La Paz
November 17, 2015
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