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 KAZAKHSTAN International Business Magazine №3, 2004
 The Kazakh Upstream Tax Regime: Comparative Analysis
The Kazakh Upstream Tax Regime: Comparative Analysis
Gerard Anderson, tax partner, Ernst & Young Kazakhstan
Gerard Anderson has over 22 years of experience in the upstream oil industry and in recent years specialized in the negotiation and implementation of tax regimes for major projects in the Caspian region. Gerard has negotiated the tax terms of several JV and PSA projects with host governments, foreign investors, and international consortia throughout the Caspian region, including projects such as Kashagan in Kazakhstan and he has worked in international export infrastructure projects in both the North Sea, and the Caspian (the BTC pipeline). He has substantial experience of tax due diligence and consulting on acquisition transactions both within Kazakhstan and internationally. He is also a member of the Legal Advisory Task Force of the Energy Charter Secretariat.
As of January 1, 2004 Kazakhstan introduced a new upstream oil and gas tax regime. The key changes to the tax system and its implications for the investment climate in Kazakhstan have been much discussed prior to and during the recent KIOGE conference held in Almaty on October 7th and 8th. In this article, we outline the new regime, compare it with an example of the international competition Kazakhstan faces, and suggest how it might be improved.
Key Changes
Companies engaged in hydrocarbons exploration and production in Kazakhstan operate in accordance with "subsurface use" contracts. Major changes to the upstream taxation effective as of January 1, 2004 determine new taxation mechanisms for upstream investors operating according to Model I taxation, generally referred to as EPT model, or Model II, generally referred to as Production Sharing Agreement (PSA).
Taxation Models
Under a PSA, the state receives a direct share of the field’s production. The costs incurred by the subsurface use are recovered from the production. The PSA model envisages payment/transfer of a share of production to the Republic of Kazakhstan and other taxes and payments applicable to this model, excluding rent tax on export, EPT and some other taxes.
In accordance with 2004 amendments to the Kazakh tax code the mechanism of production sharing calculation is identical for all PSAs signed after January 1, 2004. The share of the Republic of Kazakhstan is defined as the total value of profit production less the share of the subsurface use, which is determined as the lowest share calculated based on the following triggers:
1. R-factor (profitability indicator): ratio of cumulative income to cumulative expense for the project;
2. Internal rate of return (IRR): the discount rate at which real net present value reaches zero value;
3. P-factor (price indicator): ratio of gross income to the production volume for the reporting period.
The triggers can rapidly reduce the investor’s share of profit production from 70% to 10%.
For the PSA model the total state share, in the forms of taxes, royalty, and the state share production, must be a minimum of 20% prior to investment return, 60% after payback has been achieved, which is so-called "top-up" tax. Amendments introduced to the Tax code with respect to PSAs suggest that future offshore upstream projects will be PSA type contracts, and presumably onshore projects will be EPT contacts.
So far as EPT contracts are concerned, the old Internal Rate of Return (IRR) model, that was broadly consistent with international norms, has been replaced with a model that appears to be unique to Kazakhstan, in which the tax is determined annually, not cumulatively, and is dependent on the ratio of income to deductible expenses in the reporting year.
Further changes have been proposed, to become effective 1 January 2005, if passed into law. These include the abolition of royalty for PSAs, though the benefit of this change is somewhat limited by the fact that the "top-up" tax has been retained. So far as EPT contracts are concerned, a sort of "R Factor" mechanism, recognizing cumulative profitability on an undiscounted basis, is proposed. This, together with changes to royalty, does give some modest improvement in the IRR of investors.
Comparative Analysis
To illustrate the implications of the 2004 amendments to the Kazakh upstream taxation system, we provide a comparative analysis of upstream projects in Kazakhstan and in Libya, one of the countries which currently competes with Kazakhstan in terms of foreign investment attraction. Libya starts with strong advantages, since it has easy access to the open sea and foreign markets, has low costs, and is a more mature exploration province that the Caspian offshore.
First, we compare an upstream project in Libya with reserves of 300 mm barrels with a similar project in Kazakhstan. Then we analyze how relaxing of the Kazakh upstream tax regime "step by step" affects the upstream project model in Kazakhstan. Finally, we review the project in Kazakhstan with reserves of 1 billion barrels.
We have worked with a long-term price of $25 per barrel, while we are all aware that the current price of oil is over twice this. However, investors do not seem to regard current conditions as any sort of guide to the long-term future, and the life of subsurface user contracts is 30 or 40 years, and in fact the draft Kazakh State Budget for 2005 uses a price close to $25. In our analysis we also disregarded the suggestion that the investors should carry the state oil company for a 50% participation in each future project.
The graphs below give a comparative analysis of the results for the following hypothetical projects:
· "Libya in Libya" – a Libyan project with Libyan costs, and the Libyan tax regime.
· "Kazakhstan in Libya" – the same project with the same costs, but subject to the 2004 Kazakh PSA regime. 
· "Kazakhstan Onshore" – the same project, but with Kazakh on shore costs, and the 2004 PSA and EPT regimes.
· "Kazakhstan Offshore" – the same project, but with the costs of operating offshore in the Caspian, and the Kazakh 2004 tax regime.
· "CIT 33.5%" – a case in which the only Government take is a conventional Corporate Income Tax using a rate of 33.5%, which is the effective rate for most foreign investors operating in Kazakhstan. This regime is, in fact, not dissimilar to the current UK upstream tax regime.
Chart 1 shows the significant difference in costs between the Libyan and Kazakh environments. In Libya, the total cost, including transportation, is less than $4 per barrel. This compares with Kazakhstan onshore costs of over $10 per barrel, and offshore of over $12 per barrel, off which we have assumed $6 for oil transportation.
IRR Result
Chart 2 shows the investors IRR for the various cases, given a $25 oil price per barrel. The Kazakh offshore case, both the 2004 PSA and EPT regimes, gives an IRR of less that 3%. The same project if carried out under Libyan cost and fiscal conditions has an IRR of 20%. 
Perhaps the most interesting results on this graph are those for the project if carried out under Kazakhstan onshore conditions. The PSA regime has an IRR around 6%, and the EPT regime an IRR around 7%, but the case where state take is limited to CIT at 33.5% has an IRR of almost 15%, while the old Kazakh EPT regime would have given an IRR of 13.3%, and the proposed 2005 new Kazakh EPT regime would give an IRR of 7.66%.
The low IRR results for the Kazakhstan offshore case are not due only to the fiscal regime. The Kazakh offshore case in which government take is limited to just a corporate income tax of 33.5% has an IRR of only 8.5%, though this would improve to being close to 15% if total costs per barrel offshore could be reduced by a couple of dollars to become similar to the Kazakhstan onshore case.
The State Share of Project Rent
Chart 3 shows the stake take as a percentage of project rent. By "project rent" we mean the excess of gross project revenue over exploration, development, and operating costs prior to any form of state take. By "state take" we mean the total of all forms of tax payable, including bonuses, royalties, the state share of profit oil, corporate income tax, excess profit tax if applicable, etc. This does not include taxes suffered by others such as VAT or individual income tax of employees.
The results are presented in "nominal value", i.e. which represents non discounted cash flow value; in "real money", i.e. future cash flows adjusted for inflation into money of 2004; and in terms of future cash flows discounted at a real discount rate of 8%.
Notably, the Libyan tax regime has the lowest state take, despite the fact that it also has the lowest costs, and probably the lowest technical risks.
In the 8% discounted case, the state take is almost 200% of project rent in the Kazakh offshore case, which is a result of two major taxation mechanisms. First, in the case of the PSA regime, the "top-up tax" ensures that the total take should be at least 20% of gross project income before the investor has recovered his costs, and 60% after that. Second, in the case of the 2004 excess profit tax regime it shows that the investor can suffer a significant tax burden, and in fact pay excess profit tax, in a project that has only a modest IRR, because profitability is determined annually.
The state take under the proposed 2005 new EPT regime is reduced as shown, though the change is not substantial.
Analysis of the State Take
Chart 4 shows the total state-take under the 2004 PSA regime, and the components that make it up, as a percentage of project rent for the three 300 million barrel cases, and for a one billion barrel case. The calculations are done using cash flows discounted into 2004 money. In all of the Kazakh cases, the state take is higher than in the Libyan case.
The role of the "top-up" tax in the case that is least profitable for the investor, the Kazakh offshore case, is striking – it takes almost 15% of project rent. Furthermore, the "top-up" tax is not deductible in calculating corporate income tax, thus, the corporate income tax charge also takes a disproportionate part of the modest project rent in this relatively unprofitable case, resulting in poor return to the investor.
In the billion-barrel case, the distribution of the components of state take is strikingly similar to that for the Libya in Kazakhstan case. In each the dominant component of state take is the state share of profit oil, capturing the upside that arises in the Libyan case due to the low costs, and in the billion-barrel case due to the larger reserves.
Sharing the Upside
Chart 5 shows what happens to the investor’s IRR under the 2004 PSA regime as the price of oil increases. It is noteworthy that the investor achieves the greatest increase in IRR in the case when the project is already the most profitable, essentially because the triggers that divide the profit oil would have reduce the investor’s take to 10% early in the project, so there would be little left for the investor to lose in terms of a decrease in production share, as a result of an increase in oil price. In the cases in which the project rent is lower, the two profitability related triggers, the IRR and R-Factor would be the dominant triggers at lower oil prices, and so the investor share of profit production would, at ordinary price levels, be greater than 10%. However, as the price rises, these triggers would be over-ruled by the trigger that is based purely on the price of oil (P-factor), and so less of the benefit of a rise in prices will accrue to the investor in a project with low profitability, because he will suffer an offsetting reduction in his share of profit production.
This explains the odd shape of the line for the offshore case. It flattens out, for example in the offshore case between 35 and 45 US dollars a barrel, as the price related trigger takes the upside for the state, and only once the investor’s share of profit oil is reduced to 10% does he start to see a significant benefit from further increases in the price of oil.
Improving the Regime
Chart 6 shows how the position of an investor under the 2004 PSA regime could be improved by relaxing in turn each of the most onerous features of the regime, taking the Kazakh onshore project as an example.
Given the overriding nature of the "top-up" tax, it must be removed first for the purposes of this comparative analysis; otherwise other changes will make practically no difference. Removing this yields an improvement of IRR by 2.7%.
If profit oil were to be divided between the state and the investor using a single trigger, for example an R factor, and production divided between the state and the investor in ways seen in the mid 1990s, this would yield a further 2.5%. Replacing the production sharing and royalty mechanisms with a simple state take of 33.5% of Corporate Income Tax would take the return up to 14.5%, which may be considered to be a reasonable result for an investor.
Chart 7 shows the same process for a 1 billion barrel field.  While in the 300 million barrel case, it would look as if a simple CIT of 33.5% regime would be appropriate; in this case an arguably reasonable IRR result arises if a simplified PSA regime based on a mid 1990s R-Factor trigger is adopted.
This analysis will, it is hoped, help understanding of the current tax regime in Kazakhstan for upstream investors, and in particular the resulting poor IRR for upstream projects. Investors are looking forward to further discussions with the authorities on how project rent can be divided to ensure that there is a stable long-term future upstream investment projects in Kazakhstan. Clearly, implemented tax mechanisms should ensure that Kazakhstan receives the fair share of its oil wealth to which it is entitled. But to make that wealth flow, investors also need to have a return that is competitive by international standards. Inevitably, this leads to a process of trial and error to find the balance that will serve the needs of both sides. It seems clear that the answer will lie in developing a range of terms for different types of opportunity.
Ernst & Young is a company with 90 years of history and is represented in 138 countries. Today the company has 13 offices in 7 CIS countries with 1,600 professionals, who provide a range of services to more than 1,200 clients. In 1992, Ernst & Young opened an office in Almaty. The Kazakhstan practice of Ernst & Young is represented by 3 offices in Almaty, Astana and Atyrau, represented by more than 100 highly qualified specialists providing services to clients representing a diverse spectrum of the economy.
This publication is for general guidance only. You should neither act or refrain from acting on the basis of this publication. Ernst & Young disclaims any responsibility for all consequences of acting or refraining from acting in reliance on information contained in this publication.

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