The Evolution of Production Sharing Contracts

Mon, 09/01/2014 - 15:23

The Energy Reform passed in December 2013 allows the Mexican government to hold several types of contractual agreements for hydrocarbon exploration and production, including production-sharing agreements (PSAs). PSAs for oil-related operations originated in the mid-1960s in Indonesia, with the nationalization of the country’s oil industry. As part of the nationalization process, Indonesia created Pertamina, to work as the state’s operator, which was exclusively assigned with the responsibility of all hydrocarbon exploration and production on the national territory. The lack of human, technological, and financial resources, as well as the absence of know-how, infrastructure, and expertise within the company’s ranks, forced the Indonesian government to implement a PSA contracting model. This scheme was established to transfer international best practices to its state operator, increase oil production through the help of other oil companies, and secure a larger government take.

The PSA model allowed the external company that acted as Pertamina’s partner to deduct costs for a maximum 40%, thus promoting a benefit that amounted for 60% of the oil revenues for both Pertamina and its partner to share. In the case of not having commercial success in the exploratory activities, then the costs would be completely assumed by the external partner. In the oil industry, this deductible cost and shared benefit are known as cost oil and profit oil, respectively. Of the remaining profit oil, two- thirds would go to Pertamina and its partner would keep the rest. Although the average cost oil percentage is usually 60% of all revenues from the project, operations around the world have seen this fluctuate widely between a minimum of 35% in Libya and a maximum of 90% in Cambodia. The existing PSA contracts in Brazil stipulate a maximum 50% of cost oil during the first two years of production and 30% after that. However, the initial period could be extended if the costs have not been fully recovered during the first two years. Currently, 80 different countries around the world use the PSA contracting scheme. Out of those countries, 11 use it in combination with licensing schemes, among them Brazil, Nigeria, and Ukraine, and two with service contracts, namely Iraq and Turkmenistan. Angola combines the PSA contracts with both licenses and service contracts, while the other 66 countries use the PSA contracting system by itself.

Although the PSA system initially provides greater oil revenues for governments than licenses, due to the fact that it does not allow the cost for dry exploratory wells to be deducted, it is not as successful as licenses in incentivizing exploratory activity. Based on this, governments usually pick licensing schemes to strongly boost exploration activity or for the last production stages of mature and economically marginal fields. On the other hand, they use PSAs in projects with large amounts of reserves and low geological risk, since these can bear a greater fiscal burden. PSAs, however, present certain disadvantages when up against licenses. For starters, PSAs entail a greater administrative burden than licenses to follow up on contracts. This was one of the  main reasons why the government authorities of Russia and Kazakhstan decided to stop using this contracting model. Those two countries had so many oil blocks that they did not have the necessary resources to follow up and manage PSAs, especially due to issues with administrative and financial revisions of deductible expenses to estimate the profit oil. In such circumstances, a licensing scheme has less administrative burden for governments. These criteria could be of great importance for Mexico in the selection of the fiscal and contracting model to develop shale projects and Chicontepec.

Current PSA models contemplate several mechanisms to limit both the shared benefit or profit oil and the cost deduction. Additionally, some of the existing PSAs in the world include rentals, signature bonuses or other kind of production bonuses, and, in some cases, royalties. Bonuses, however, and especially signature bonuses, are one of the elements that most affect the retrogression of oil tax systems, regardless of the contracting model used. Signature bonuses are paid by operators at the beginning of the contract, without being dependent on the field’s production. It is of the utmost importance to consider that not all oil fields will produce, and that those that yield hydrocarbon production might take too much time to develop, particularly those in deepwater. Due to this, most governments are inclined to pay certain bonuses at the beginning of the contract, despite of their regressive nature. With the PSA contract used for the Libra pre-salt field in Brazil, the government managed to obtain US$6.2 billion in signature bonus.

From a fiscal standpoint PSAs are, in principle, more convenient than licenses since they allow the government implementing them to collect money from the beginning of the field’s production, instead of having to wait for the external oil company to raise a profit, as happens with licenses. They also allow the government to extract a larger take, since there is no cost deductibility when hitting a dry exploration well. This, however, has led project development in many countries to increasingly respond to fiscal optimization stratagems, instead of responding to integrated field and reservoir management strategies. This background seems to initially endorse the use of a hybrid contracting system in Mexico. The main objective of this hybrid system should be to balance out the effects of maximizing oil revenues, incentivizing exploration, and simplifying and streamlining the government’s supervision and management of oil contracts. The PSA model could be extremely interesting for projects in shallow waters, deepwater projects with certified reserves, and brownfield projects such as mature fields. On the other hand, the licensing model would be recommended for the development of shale projects, Chicontepec, and for deepwater projects with prospective resources that have not yet been classified as reserves. The economic conundrum of which parameter to privilege as the functional objective of the oil industry ties in with the dilemmas faced by central banks. These banks usually have two alternative mentalities: one focused on controlling inflation and the other on emphasizing the promotion of economic growth. The oil world has an equivalent predicament, opposing the objective of maximizing government take with incentivizing exploration and, as a consequence, production. Time will tell which economic philosophy prevails in the new Mexican oil industry.