My earlier blog on India’s oil exploration policy (16 November 2012) has elicited responses from some old friends. Their comments have drawn my attention to two issues that are engaging the upstream petroleum (exploration and production) sector. The first relates to the ‘gold plating’ of exploration and production costs and its impact on government take from the producing field; the second concerns effective regulation of the upstream sector. Before taking up these two topics in my next blog, I feel it is necessary to acquaint my readers with the fiscal arrangements in place in the upstream petroleum sector. This blog will, therefore, explain the fiscal regime with some mathematical examples and highlight the rationale of its operation.
The New Exploration Licensing Policy (NELP) fiscal regime is modelled on the fiscal regime adopted for bidding rounds in the 1980s and 1990s, with some modifications. The contractor is entitled to recover in full the aggregate costs incurred on exploration, development and production operations as well as royalty payments (these are collectively referred to as cost petroleum). The contractor can opt to allocate 100% revenues from production to recover costs as long as aggregate costs yet to be recovered are greater than the revenue realised in any financial year or can opt for a percentage less than 100%: this is a biddable item. A notable feature of the NELP production sharing contract fiscal regime is that all costs (whether exploration, development, production or royalty payments) which are not recoverable from petroleum revenues in a particular year can be carried forward to subsequent years and recovered from revenue realised in those years. The pre-tax investment multiple (IM) for calculating the sharing of revenue net of cost petroleum between the contractor and the government in any year is worked out by the following formula:
IMn+1 = (En+Dn+Pn+Rn) +PPn – (Pn+Rn)/E*+D*
IMn+1 = Investment multiple in year n+1
En = Cumulative exploration costs recovered for all years upto and including year n
Dn = Cumulative development costs recovered for all years upto and including year n
Pn = Cumulative production costs recovered for all years upto and including year n
Rn = Cumulative royalty payments recovered for all years upto and including year n
PPn = Cumulative profit petroleum entitlement (including incidental income from petroleum operations) of the contractor for all years upto and including year n
E* = Cumulative exploration costs upto and including year n
D* = Cumulative development costs upto and including year n
Cost petroleum recovered by the contractor together with profit petroleum to which it is entitled (both computed over the contract period) constitute the gross revenue of the contractor. The IM being computed on net income, production costs (P) and royalty payments (R) are deducted from cost petroleum in its computation. Since exploration and development costs are incurred largely in the initial years of a PSC and taper off in later years (unless fresh discoveries warrant further expenditure on exploration and development), En+Dn will over time coincide with E*+D*. Essentially, it is PP, the profit petroleum share accruing to the contractor over the contract period, which will determine how high the IM rises. This value of the IM has great significance for the share of profit petroleum taken by the government on a year to year basis, as will be evident in the succeeding paragraph.
The main component of the bid evaluation process in the NELP is the percentages of profit petroleum offered to government by bidding companies in the first (less than 1.500) and last (greater than 3.500) tranches of the IM, since royalty payment is mandatory. Based on these two percentages, the percentage values for tranches between 1.500 and 3.500 would be interpolated based on a linear scale. An example would help clarify the picture:
|Pre-tax IM||Government share (%)||Contractor share (%)|
|Less than 1.500||10||90|
|1.500 – 2.000||20||80|
|2.000 – 2.500||30||70|
|2.500 – 3.000||40||60|
|3.000 – 3.500||50||50|
|Greater than 3.500||60||40|
As is clear from the above table, the share of government in net revenue rises progressively as the IM moves to higher tranches of profitability.
A view has been voiced in public discourse that the pre-tax IM method of determining government share is fraught with the danger that the producing company would be tempted to inflate (gold plate) costs to reduce the profitability of the venture and thereby confine government share to the lowest one or two tranches as well as reduce the quantum of profit petroleum available for division between the contractor and the government. It has, therefore, been suggested that a flat share of gross revenue (based on production) be taken by the government so that the ‘evils’ of gold plating do not lead to a reduction in government share. There are at least three problems with such an approach:
(a) royalty on oil and gas at between 10% and 12.50% of gross value is already levied on companies. A further flat rate levy implies an extension of the royalty approach. It also makes a risky, cost-intensive venture unviable at the outset by taking a large chunk of the pie away from the contractor, postponing the payback on its investment;
(b) the flat rate approach is insensitive to the fluctuations in economic rent arising from windfall gains. This could arise on account of rise in oil/gas prices, as has been witnessed over the past decade. Oil prices have climbed over fourfold since the turn of the century. A flat rate revenue sharing approach entered into in, say, 1998 (when oil prices were under US$ 20) would have greatly reduced the revenue share of government today (when oil prices stand at over US$ 80). There is also another possible scenario: a dramatic drop in exploration and development costs after contract execution because of advances in technology would also confer huge benefits to the contractor, with the government not sharing in the windfall gains.
(c) a flat rate regime could also adversely affect the exploration and development of marginally profitable discoveries. A ‘one-size fit all’ flat tax regime does not account for the varying geological prospectivity and the differing costs of exploration and exploitation of discoveries in different petroleum basins (both onshore and offshore) of the country. Varying the flat tax rate across different regions would invite the accusation of arbitrariness in rate fixation.
This is not to discount the need for vigilant monitoring of the contractor’s operations to ensure that government is not deprived of its legitimate share of profit petroleum. However, merely because, as a society and government, we lack confidence in our regulatory institutions is no reason to look for simplistic fiscal solutions that deny government its rightful share of economic rent from petroleum operations. This is a topic we will turn to in the next blog.