Request you to kindly drop in all your mails/queries to support@infraline.com or call us at
+91-120-6799125 (D); +91-120-6799100 (B)

PSC Vs Royalty Tax: Are we asking the right question?, Vivek Bhatia, Consultant, Energy and N Visvanathan, Senior Manager, Energy, PwC India


N Visvanathan
Senior Manager, Energy, PwC India

A debate has begun in the India oil and gas sector with the setting up of Rangarajan Committee on the need to review future Production Sharing Contracts (PSCs). In this context, Vivek Bhatia, Consultant, Energy and N Visvanathan, Senior Manager, Energy, PwC India, raise the question whether India should amend its future PSC contracts and if yes, what aspects in current fiscal system need attention. 

Blurb: Since the PSC cost recovery process involves a lot documentation work and approvals at different stages, the fallout is that it takes a lot of effort and time on part of government in reviewing these submissions and operator in drafting these submissions and responding to queries. The end result is that there is an increase in administrative burden for both the operator and government.

Speak: Fiscal systems are not easy to design and sometimes balancing the interests of all the stakeholders could be quite time consuming! 

 

“All the natural wealth on land and in the waters falls under the jurisdiction of the State and should be used for the greatest benefit and welfare of the people.”
-Article 33, Constitution of the Republic of Indonesia, 1945

Production sharing contract (PSC) addressed the above concern– in an era where many developing countries did not possess the requisite technology, skills, equipment and/or capital to explore and produce oil and gas reserves, and were dependent on International Oil Companies (IOCs) for extracting domestic hydrocarbon reserves for which they would have had to provide sufficient incentive to cover the risks involved, but at the same time wanted to ensure the investments so made, were protected and that the host country controlled the use of the hydrocarbons so discovered.

It turned out to be a contract which had all the makings of a law. It could also be tweaked, if required to reflect inherent complexities within different types of acreages (offshore, on-land, deep-water) or be re-written to incorporate lessons learnt during different licensing rounds.  It ensured that the IOC, contracted by the host government (HG) to undertake E&P activities, brought in the requisite capital, technology and skills as well as carried the entire investment risk during the exploration stage. If successful, the IOC was suitably compensated by not only being allowed to recover all the contract costs (Cost oil) but also allowed to partake in the production (Profit oil).

Contrary to the above scenario, there existed a precedent of a different nature in hydrocarbon exploration and production business. This precedent was largely followed in the OECD countries and had its clauses drafted on lines similar to that of coal mining– industry that predates oil exploration. A typical concession agreement, for a specific block over a given duration, transferred the entitlement of hydrocarbons, if discovered, to the IOC at the wellhead (at the extraction point). The host country received royalties (Royalty oil) and taxes in compensation for the use of the resource by the IOC, in addition to signing bonus or a license fee at times. As in the case of PSC, the IOC has to carry the entire investment risk.

The trend continues even today; quite a number of non-OECD and developing countries practice PSC - Indonesia signed the first production sharing contract in 1961 in Aceh and post formation of OPEC, many developing countries followed suit. Licensing or Royalty/Tax (R/T system) on the other hand, is/has traditionally been prevalent in OECD/Developed countries.

As we know the above two are not only so-called “fiscal systems” in the hydrocarbon industry. There are many variants and hybrids in use today depending upon a regime’s hydrocarbon resource endowment levels, energy needs, technology/skill levels, etc. Given these parameters, a good fiscal system then tries to strike the right balance of risk shared and rewards obtained from a petroleum project. While easier said than done, there’s often a conflict between the two parties (operator and host government) which try to maximize the rewards and shift the risk as much as possible.

India’s case is not different. In India, circa 1992, the Indian government too, as part of its policy of attracting foreign investments in the oil industry, allowed foreign and domestic private companies to participate in the development of small to medium sized oil and gas fields. The Ravva field was included in the first bidding round for these fields and its award to the consortium was made subject to the finalisation of the PSC with ONGC and the Government.

Ever since the first PSC was signed in India, E&P sector in India has come a long way starting from 2 companies and 3 producing basins in 1990 to 71 companies and 10 Producing basins in 2009. The number of blocks awarded went up substantially after the first NELP round was held in 1999.To quote a few numbers; 235 blocks have been awarded so far within NELP regime, 68% geographical area has been awarded for exploration. Needless to say, to reflect the changing needs of both the contractors and the government, amendments to bidding parameters and PSC are continued to be made. These aspects reflect the attractiveness of PSC for investors.

However recently, in the wake of CAG audit conducted on oil and gas blocks operated by some operators to determine whether revenue interests of Government of India were protected and compliance related processes properly followed by them. Subsequently, Govt. Of India setup Rangarajan committee to look into future production sharing contracts which has brought to fore a debate on whether India should amend its future PSC contracts and if yes, what aspects in current fiscal system need attention.

When carefully looked at model PSC for today, it is quite evident that India has a” hybrid” system factoring both PSC regime and concession or Royalty-tax regime (R/T). While the tenets of costs recovery and production sharing reflect the makings of a classical PSC contract, India government has put in place safeguards such as upfront royalty which ensures a minimum payment for the minerals extracted, royalty calculation (ad valorem) and production sharing methodology (a sliding scale linked to revenues earned and expenditures incurred by the operator) which ensures an appropriate government take in economic rent1 with increase in value of minerals extracted, and finally income taxes - all these safeguards being adopted from basic principles defined within a typical R/T system. In fact, the preferred regime for CBM policy is on the lines of a concession regime (no cost recovery, no production sharing, only royalty, commercial bonus, production linked payments and taxes).

So, once the above is realised and well understood, the question then no longer becomes choosing between two different fiscal systems, it is more a question of how well can we learn the lessons of past and move forward by quickly rectifying the inherent opportunities, for improvement, if any, in the system. In this context, one of the aspects which have been very much a topic of discussion over the recent period is the element of ‘cost recovery’ and its implications over the past.

Now, Indian PSC allows for cost recovery of contract costs (exploration costs, development costs and production costs) in addition to royalty payments made to the state government. The contract also mentions the costs which are not recoverable (e.g.: financing costs such as interest, commission, etc.; amounts paid with respect to non-fulfilment of contractual obligations; expenditures on creation of any partnership; etc.). The process (see table below) followed for recovery of costs is also mentioned in the contract.

How is cost recovery of contract costs and royalty payments done according to the PSC contract?

  • Contractor bids for a % of total value of Petroleum produced in the year as its entitlement (Cost petroleum) for the purpose of cost recovery

  • Contractor converts all costs, expenditure, sales and revenue for the purposes of cost recovery into production equivalents, and vice versa viz both in physical and monetary terms, using the relevant prices

  • Contractor makes provisional estimation of its entitlement of cost petroleum on a quarterly basis and matches it with a final calculation at the end of the year. All such deliveries require approval from Management committee (MC).

  • For the purposes of cost recovery, cost estimates given by the contractor towards Minimum work program is taken as the benchmark and any material difference between the actual and the benchmark is allowed only when MC agrees that the difference is due to change in circumstances after the contract comes into effect. Such provisioning is not there for on-land blocks wherein a lower of benchmark and actual costs (during exploration period) incurred is taken

Since the PSC cost recovery process involves a lot documentation work (quarterly statement of costs, expenditures, distinguishing between exploration, development and production costs and separately identifying all items of costs within the categories mentioned in the contract) and approvals at different stages, the fallout is that it takes a lot of effort and time on part of government (reviewing these submissions) and operator (drafting these submissions and responding to queries). The end result is that there is an increase in administrative burden for both the operator and government. Administering hundreds of PSCs each having its share of analysis and subjectivity on a daily basis could very well become a manpower challenge for government if production starts in even 15 out of 235 awarded blocks.

CAG audit report has made suggestions which could obviate the need for cost audits and approvals. It is of the opinion that since profit sharing is linked to cost (expenditure incurred on exploration and development), the onus is on government to ensure the operations are carried out in cost-efficient manner. Hence the need to put in place stringent measures and checks to control costs. If the profit sharing mechanism were to be replaced by a royalty linked to production levels (which is much easier to verify), it would put the ball in operator’s court to ensure that costs are controlled.

From IOCs perspective as well, the cost oil is not the most efficient way of recovering all costs given the fact that it does not take into account the financing costs and the time value of money. So while the discussion is on and Rangrajan committee would surely look into it, it only goes to show that fiscal systems are not easy to design and sometimes balancing the interests of all the  stakeholders could be quite time consuming!
_______________________________________________________________________________________
[1] Economic rent can be defined as income earned without any enterprise, without any cost of production, to get excess of rental value over and above the actual cost of production