One of the key parameters in determining the attractiveness of a country for exploration is the level of Government Take - the lower the take, the more attractive the opportunity. A low tax rate, however, can be associated with a high risk that this will be changed in the future if windfall profits are realized. To diminish this fiscal risk, production sharing contracts (PSCs) have been employed in many countries, but these restrict companies' ability to book reserves under current Securities and Exchange Commission (SEC) rules. As such, companies appear to "lose" barrels as oil price increases.
Modern concession licenses could be adapted to include the fiscal stability that PSCs can offer, without the penalty of reducing bookable reserves. A critical component of this is the inclusion of progressive tax rates based on the economic performance of projects and a proper appreciation of the prospectivity of the acreage on offer in establishing the level of Government Take.
Investors appear to face a choice - accept fiscal risk or campaign for predictable fiscal regimes inherently designed to limit their capture of windfall profits.
Where do the barrels go?
Companies "lose" barrels under higher oil prices because of the SEC rules governing the booking of reserves under PSCs.
Under a PSC, the investor retains a proportion of production to recover its costs and the remaining production ("profit oil") is then divided between the government and the investor. Current SEC rules entitle companies to book only the reserves associated with their net share of production. Moreover, the rules insist that year-end prices (about US $40/bbl in 2004) are applied to projections of future production rather than the company's own long-term planning price (e.g. $25/bbl).
When the oil price increases, the amount of reserves that can be booked decreases because less production is required to cover costs. Moreover, in many PSCs the government's percentage share of profit oil will increase because the projects become more profitable (e.g. the prolific deepwater Angolan PSCs).
Under concession licenses, companies can book all reserves discovered within the license area. The split of a company's reserves between concession and PSC regimes can, therefore, have a significant impact on their reported reserves/production ratios and reserves replacement ratios.
Why are PSCs popular?
First, the PSC enables the investor to channel all liabilities to the state (e.g. Finance Ministry, Energy Ministry, Customs and district/provincial authorities) through the National Oil Company (NOC), which is normally the licensee and its partner in the PSC. Countries with an emerging petroleum industry may not have the skill base to populate several different petroleum agencies at once, and the NOC acts as the main interface with foreign investors, organizing and awarding contracts, co-managing operations and gathering the state's revenue.
The pervasive role of the NOC is, however, being called into question in several countries, particularly as some NOCs have started operating as an International Oil Company (IOC) overseas. The NOC's dual domestic roles of co- licensee and the recipient of the state revenue is increasingly perceived as a potential conflict of interest. Notably, Algeria and Indonesia have recently decided to move domestic regulatory and revenue-gathering responsibilities away from the NOC to other government agencies.
The second principal attraction of PSCs for the IOC is the perceived fiscal stability that can be incorporated through clauses that ensure one of the following:
* The fiscal regime in place at the time of signing a contract will persist for the duration of the contract, regardless of future changes in the general tax regime - e.g. Azerbaijan, Indonesia; or
* The NOC agrees to meet the contractor's tax liability from its share of profit (thereby removing any impact of changing tax rates) - e.g. Egypt, Gabon; or
* Any adverse changes in the generally applicable tax regime will be balanced by an adjustment to the other economic terms within the contract - e.g. China.
It is the ability to significantly reduce the fiscal risk associated with concessions that is often the main reason why investors prefer a PSC. Under a concession regime, the state can increase the tax rate whenever it feels appropriate, and some countries (e.g. Argentina, Brazil, Denmark, United Kingdom, Russia, Venezuela) have done just that in recent years. These increases can apply to existing production and future licenses, and there is little the companies can do to stop them. Currently there is widespread pressure in several countries for more increases as a response to recent high prices. The UK government, for example, is being lobbied for another increase in the corporate tax rate, which would follow a long history of changes in the tax rate since production began in 1975.
This fiscal instability adds significant risk to long-term investments, and if tax increases are applied retroactively, this can make a fundamental change to the full-cycle economics of projects.
Fiscal risk and predictability
Fiscal terms would not need to be changed or re-negotiated if the government's share of the economic rent generated from petroleum exploration and production (E&P) activities was always regarded as appropriate both by government and by investors. A tax (or state profit share) rate of 30%, for example, may be appropriate for a marginal development but will appear low if there is a windfall (and vice versa if the tax rate was 85%).
An inherently flexible fiscal regime can be achieved by making the tax or profit share rate progressive, increasing or decreasing the rate according to project economics. To date, sliding scale rates have been most widely used in PSCs but are also included in some concession regimes. The earliest PSCs use production rates as the basis for determining profit shares, but there are concerns that these contracts are unsuitable under high prices, and the possibility of re-negotiation is being discussed in some countries.
The later generation of PSC regimes link profit shares directly to price (e.g. Congo (Brazzaville)) or even a hybrid of both production and price levels, as follows:
To capture the effects of fluctuations in costs, as well as production and prices, several fiscal regimes now link at least part of the fiscal regime to a sliding scale based on the overall profitability of a project - measured by rate of return or a revenue/costs ratio ("R" factor). The impact of such regimes is highlighted in Figure 3, which shows the increase (or decrease) in the Government Take from a hypothetical 100 MMbbl field when the price increases from US $22/bbl to US $35/bbl. The most progressive regimes - India, Angola (deepwater) and Azerbaijan - are all PSCs that link the state's profit share to the profitability of the projects.
Figure 3 also shows that in more than half of the regimes considered, the government's share of the economic rent from this field actually decreases as prices increase. This is normally a function of the fiscal terms being levied on project revenue rather than profits, such as royalty; or indirect taxes, such as value-added tax (VAT). A decrease in the Government Take when windfall profits are realized often results in political pressure for additional taxation.
Employing progressive tax or profit share rates can establish predictability in the fiscal regime. When investors analyze future economics scenarios, including marginal and windfall economics, they know what the rate will (rather than might) change to under the different circumstances.
What do investors really want?
There are, therefore, a number of intrinsic problems with both standard concessions and PSCs. Concessions are prone to fiscal risk, and PSCs have a negative impact on booking reserves. The solution appears to be a modification of the concessions regime: to incorporate the stabilizing aspects of a PSC without incurring the reserves "penalty."
A critical condition for the success of these new licenses will be for the state to agree a fiscal package for each license, which will be enshrined in the license for its duration. For this to work, the rates need to be:
* Progressive, and
* Be able to accommodate marginal and windfall economics and reflect the perceived risks (e.g. expected success rates, discovery sizes) in the license area.
In addition, the licensee would be exempt from any generally applicable taxes other than those set forth in the license.
As a further consideration, the highest level of the tax rate could be made a bid factor in a licensing auction, similar to the recent auction of blocks in Libya and the 1996 E&P round in Venezuela. This would enable investors to demonstrate their willingness to share upside with the host government, with the bidder offering the highest rate acquiring the license. Alternatively, the terms can be fixed for each license, and the winning applicant is the one that bids the highest signature bonus to acquire it (as is the practice in North America and West Africa, in particular).
Analysis drawn from Wood Mackenzie's recently completed multiclient study titled "Global Oil and Gas Risks and Rewards" shows the average full-cycle Government Take from 54 areas, based on IOC exploration activity between 1994 and 2003 and the economics of the resulting discoveries, assuming a future oil price of US $35/bbl (see Figure 4). The 10 areas that discovered the most commercial reserves during the decade are highlighted in red on the chart, which shows that eight of the 10 areas have an average Government Take greater than 70%. These are a combination of PSCs and concessions, highlighting that it is the rates chosen, rather than the type of regime, which determines the economic attractiveness of the fiscal regime.
Some investors dislike progressive fiscal regimes because they are designed to cap their exposure to windfall profits. These investors prefer, instead, to accept ad hoc changes to the tax rate as another risk associated with exploration that needs to be factored into their investment analysis and trust their persuasive powers to prevent tax increases and secure tax decreases wherever possible.
Thus, industry and government appear to have a choice - embrace (and campaign for) predictable fiscal regimes, which can be delivered through progressive taxation, or accept the risks associated with ad hoc future changes to the fiscal terms. As the current debates over fiscal terms are resolved, it will be interesting to see if either of these options becomes standard.
Wood Mackenzie's Global Oil and Gas Risks and Rewards (GOGRR)
GOGRR is a study that:
* Compares the full-cycle economics of exploration for oil and gas in over 60 countries;
* Includes annual data for exploration drilling, success rates and reserves discovered between 1994 and 2003;
* Has field-by-field values for each commercial discovery made in the period to enable global comparisons of finding, development and production costs;
* Calculates pre-and post-take economics under three future price assumptions; and
* Compares the drilling costs with the value of discoveries made to establish which areas have created value from exploration - and which have destroyed value.
GOGRR is available now and is delivered as a 300-page report and a software package including all the underlying data and an optional interactive tool for creating bespoke analyses. Visit http://www.woodmac.com/GOGRR.htm for more details.
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