A Tax for Diversification, or Diversified Tax?
Analysis of Subsoil Users? Tax Burden Resulting from Changes to Tax Legislation
Janat Berdalina, Managing Partner, KPMG, Kazakhstan
Natalya Yemelyanova, Tax Consultant, KPMG, Kazakhstan
The authors would like to continue the analysis of the tax burden and tax payment structure of the mineral resources industry in Kazakhstan, which they started in previous articles1 in Invest Kazakhstan magazine. However, while in the previous articles they analyzed the causes of an increase in tax payments from the mineral resources industry and compared the tax burden on different sectors of the Kazakh economy, in this article the authors analyze how subsoil users’ tax burden and tax payment structure will change as a result of changes introduced to Kazakh tax legislation in 2004. (Factors Influencing the Growth in Tax Revenues from the Oil and Gas Sector in 2001, Invest Kazakhstan, April 2002, Tax Burden in Kazakhstan, Invest Kazakhstan, January 2003.)
In 2001 and 2002 the composition of taxes paid by enterprises operating in the mineral resources industry was rather stable and not subject to considerable change. Total tax payments amounted to approximately 25-30% of the value of subsoil users’ output. The tax burden comprised primarily corporate income tax, royalties and social tax. In 2002 these taxes accounted respectively for 47%, 15% and 10% of total taxes paid by subsoil users. Other taxes and special payments of subsoil users, including excess profits tax and the state’s share of production under production sharing agreements, amounted to only 2%.
As a result of changes introduced to the Tax Code with effect as of 2004, the tax burden on subsoil users and the composition of their tax payments may significantly change. Although subsoil users, like all other taxpayers, will enjoy a reduction in rates of personal income tax, VAT and social tax, there are other changes that apply only to subsoil users, such as the introduction of a new tax on exported crude oil, changes in the rules for calculating excess profits tax and the state’s share of production under a production sharing agreement, and the introduction of royalty rates in the Tax Code.
Subsoil users in Kazakhstan may be subject to either of two different tax regimes: the first regime applies to subsoil use contracts with statutory taxation and the second regime applies to a production sharing agreement2 (PSA). (The Tax Code employs the term “production sharing contract,” whereas we use the term “production sharing agreement” in this article as a synonym for “production sharing contract.”)
Taxes such as corporate income tax, personal income tax, VAT, social tax, royalties, bonuses, vehicle tax, and environmental pollution fees apply under both models of taxation.
In addition to the abovementioned taxes and payments, subsoil users applying the first model of taxation are subject to land tax, property tax, excise tax on crude oil and gas concentrate, excess profits tax and a new tax on exported crude oil. The second model provides for payment of the state’s share of production under a PSA in place of the aforementioned taxes applicable under the first model.
In this article we consider changes in tax legislation relating to the corporate income tax and social tax that are payable by all taxpayers, and taxes and special payments that are sp ecific to subsoil users. It is important to mention that changes in the Tax Code will not apply to contracts that were concluded prior to January 1, 2004, because such contracts stabilize the applicable tax regime that is stipulated in the contract.
Taxes Payable by all Taxpayers
Corporate Income Tax
The tax burden attributable to corporate income tax clearly illustrates the dominant role of this tax in the taxation of subsoil users. This tax accounts for almost half of the total tax paid by companies operating in the oil and gas and mining industries. Accordingly, changes in the Tax Code related to corporate income tax can significantly affect the tax burden on subsoil users.
The operations of oil and gas and mining companies are characterized by a high level of capital expenditures and debt financing. Therefore, depreciation policy for taxation purposes and the deductibility of interest expense can significantly affect the tax base for corporate income tax purposes.
Many investors believe that the declining balance method of depreciation used for taxation purposes in Kazakhstan and the current maximum depreciation rates under Kazakhstan’s tax law do not properly contribute to the renewal of fixed assets and to economic growth in Kazakhstan. For example, the depreciation period for processing equipment that costs US$1 million will be 20 years for a taxpayer applying the highest depreciation rate stipulated for mining industry equipment (25%). The depreciation period for property, plant and equipment of similar cost used in the oil and gas industry will be 38 years, because the maximum depreciation rate for such equipment is 15%.
To stimulate the renewal of fixed assets, the tax legislation that was in effect from 1995 to 1999 allowed taxpayers to deduct the full cost of purchases of technological equipment and construction costs as a period expense. However, in 2000 this provision was annulled and now the only tax incentive available for new equipment and machinery is the use of double depreciation rates in the first year of asset use.
The provisions of the Tax Code regarding depreciation remain largely unchanged. Changes to the procedure for deducting the cost of fixed assets were as follow:
• an increase in the maximum depreciation rates for some subgroups of fixed assets, such as motor vehicles, passenger cars, computers, instruments, production and operating stock, measuring instruments, and laboratory equipment;
• an increase in the specified value of an asset subgroup year-end balance below which the balance becomes immediately deductible for corporate income tax purposes (the increase is from 100 to 300 monthly index factors); and
• an increase in the maximum deductible rate of repair expenditures for some groups of fixed assets from 15% to 20% of the balance of the asset group.
All these changes will take effect on January 1, 2005.
Amendments to the Tax Code changed the limits on deductibility of interest expense. The new law permits taxpayers to deduct interest paid on loans from resident lenders in full, with no restriction on the interest rate that can be deducted. The deductibility of interest paid to nonresidents depends on the borrower’s equity-to-debt ratio. A subsoil user can deduct interest paid to a nonresident lender in full, provided its equity-to-debt ratio is not less than 1/4.
Previously there were limits on the interest rate that a borrower could deduct. The maximum rate was 2 times the official refinancing rate established by the National Bank of Kazakhstan for loans in Kazakhstan tenge and 2 times LIBOR for loans in foreign currency. Further to these limits, in 2002 and 2003 there was an additional limitation that restricted the portion of interest that was deductible on a loan from a foreign lender. The maximum amount of interest that was tax-deductible on loans from foreign lenders was 50% of the amount of interest payable to foreign lenders.
The recent changes will enable taxpayers potentially to fully deduct interest expense and to accelerate deductions for depreciation of fixed assets, which may result in a reduction of the tax burden attributable to corporate income tax.
In 2004 amendments to the Tax Code introduced regressive social tax rates with a maximum rate of 20% and a minimum rate of 7%. The amendments also introduced lower social tax rates ranging from 11% to 5% for expatriate managerial, administrative, technical and engineering staff. Previously, the social tax rate was 21% for Kazakhstan nationals and 11% for foreign specialists. Accordingly, the recent changes will reduce a company’s tax burden.
Taxes and Subsoil Users’ Special Payments under the First Model of Taxation
In addition to the general taxes payable by all taxpayers, companies operating in the oil and gas and mining industries have an additional burden in the form of special taxes and payments to the state. Prior to 2004 the level of these taxes and payments was determined in negotiations between the investor and the authorized governmental body for a particular project, on the basis of such technical and financial indices as payback period and internal rate of return (IRR).
Royalty rates were established in each subsoil use contract to yield a project IRR that was targeted to range from 12% to 20%. Under some subsoil use contracts, royalty rates can change, depending on both production volumes and prices. The excess profits tax should apply if IRR exceeded 20% as a result of an increase in selling prices or an improvement of other factors that were not taken into consideration during an original analysis of the project.
Therefore, the key element of the additional tax burden was the royalty, while the emphasis on excess profits tax was minimal at the contract negotiation stage. This explains the high percentage of royalty in the composition of subsoil users’ tax payments and low portion of excess profits tax.
Starting from 2004 one aspect of subsoil user taxation under the first taxation model changed fundamentally. The estimated project payback period and IRR will no longer be of importance in determining royalty rates. Consequently, an obligatory tax review will no longer be required for taxpayers who use the first model of taxation. The degree of the additional tax burden will now depend only on project indices, such as the volume of production, profitability rate for the reporting period, volume of exports, and market oil prices.
Starting this year the royalty rates will be established by law and will no longer be a matter of negotiation. The royalty rates for hydrocarbons are now stipulated in the Tax Code and vary from 2% to 6%, depending on the volume of cumulative oil production for each calendar year. The taxable base for royalty is the value of oil produced, as measured on the basis of the weighted-average selling price for the tax period (month or quarter).
The royalty rates for other minerals, including gold, silver, platinum, other precious metals, and precious stones, will be established by the Government of Kazakhstan.
Because previously royalty rates were established individually in each subsoil use contract, currently it is difficult to assess the effect of these changes on the tax burden and composition of subsoil users’ tax payments.
Tax on Exported Crude Oil
The payers of this tax will be legal entities and individuals exporting crude oil, except for subsoil users that have concluded PSAs. This means that the tax will apply not only to subsoil users that have concluded subsoil use contracts (other than PSAs) after January 2004, but also to traders exporting crude oil purchased from subsoil users in Kazakhstan. For these traders it will not matter whether the exported oil was produced under a subsoil use contract concluded before 2004 or under a contract concluded after 2004 or under a PSA.
The tax rate is progressive and depends on market price for similar oil grades sold on the international market. The tax rates range from 1% to 33% of the value of exported oil, as adjusted for transportation costs. The tax will not apply if the market price is lower than US$19 per barrel, and at the current price of US$30 per barrel, the tax rate will be 23%.
A discount or surcharge will be assessed if the quality of the subsoil user’s crude oil differs from the quality of the crude oil mixture transported through a pipeline. A list of oil grades will be determined by the Government on the basis of a database developed by the Geology Committee of the Ministry of Energy and Mineral Resources.
The tax period for the tax on exported crude oil is the calendar month.
Excess Profits Tax
The rules for calculating excess profits tax have changed. The tax base for excess profits tax is a subsoil user’s net income in excess of 20% of deductions claimed for corporate income tax purposes. The tax base can be adjusted by 10% for expenses incurred for training local employees and (or) an increase in fixed assets.
The changes substantially simplify the calculation of excess profits tax, because no calculation of IRR is required. However, the tax is triggered more easily now, because it can apply regardless of a subsoil user’s return on investment. The previous rules permitted recovery of capitalized and current expenses and an adjustment of income for inflation. Now, the taxable base can be adjusted by up to 10% for the abovementioned expenses to train local employees and (or) increase fixed assets, but excess profits tax under new subsoil use contracts can also arise during the first years of production as a result of the changes. Due to the capital intensity of oil and gas and mining operations and the limited ability to deduct capital expenses (through amortization), a subsoil user might have sufficient net income in a particular year to trigger this tax, while still reporting a relatively low IRR for the project.
The excess profits tax rates were also significantly increased and now vary from 15% to 60% of the taxable base. Earlier the excess profits tax rates varied from 4% to 30% of the taxable base.
As mentioned above, starting in 2004 excess profits tax will depend only on the profitability of a project for a given reporting period. To demonstrate how the profitability of a project will affect excess profits tax and the subsoil user’s tax burden, we provide the sample of profitability measures and corresponding tax consequences in Table 1.
These figures illustrate that the additional tax burden resulting from excess profits tax is relatively low if profitability is under 30% but sharply increases as profitability increases.
Summarizing all changes mentioned above, the revised taxes on oil and gas companies under the first tax regime may vary as follows:
• royalties - from 2% to 6% of the value of oil produced;
• tax on exported crude oil - from 0% to 33% of the value of oil exported;
• excess profits tax - from 0% to 30.9% of gross annual income.
The additional tax burden on mining companies will be somewhat lower, because these companies are not subject to the tax on exported crude oil and the profitability of mining companies is usually lower than the profitability of oil and gas companies. The additional tax burden resulting from the royalty changes can be evaluated only after the Government establishes the royalty rates.
Taxes and Subsoil Users’ Special Payments under the Second Model of Taxation
The second model of taxation applies to subsoil users operating under a PSA. Under a PSA, oil production after the payment of royalty is divided into cost oil and profit oil. Cost oil is awarded to the subsoil user and is used to recover expenses incurred to conduct operations under the PSA. Profit oil remaining after allocation of cost oil must be split between the subsoil user and the state.
The tax treatment of subsoil users under this model of taxation has also changed substantially. Prior to 2004, financial measures were of critical importance in determining royalty rates, the state’s share of production under a PSA and the maximum amount of cost oil to be awarded to the subsoil user in any particular year. As discussed above, starting in 2004 the royalty rates for oil are specified in the Tax Code. In addition, the Tax Code now establishes transparent, though complicated, rules for determining the state’s share of production under a PSA. Earlier, this issue was a key point of negotiations between a potential investor and the Kazakh Government. The maximum amount of annual cost oil remains the only figure that depends on the feasibility study of the project. As before, this figure will be established separately in each PSA and will depend on the economic value of the deposit under development, within limits established by the Tax Code.
Maximum Amount of Cost Oil
Starting in 2004 the maximum amount of annual cost oil in any PSA is limited to 75% of total annual production prior to the payback date, and 50% in subsequent periods. Previously, the Tax Code stipulated that the maximum amount of annual cost oil was limited to 80% of total annual production.
Sharing of Profit Oil
According to the recent amendments to tax law, the value of profit oil should be computed on the basis of weighted-average market prices of similar crude oil grades. In contrast, most PSAs concluded before 2004 stipulate that actual selling prices should be used for profit oil valuation purposes.
Starting in 2004 a subsoil user’s share of profit oil depends on three specified indices measured for the subsoil user: R-factor (profitability rate, measured as cumulative income for the project, divided by cumulative expenses), internal rate of profitability (the same as IRR) and P-factor (price). The subsoil user should calculate all of these indices for each reporting period and determine its share of profit oil based on the index that results in the lowest percentage of oil to the subsoil user.
The Table 2 indicates the subsoil user’s share and the state’s share of profit oil corresponding to various index values computed in accordance with Article 312-1 of the Tax Code. To illustrate, if a subsoil user computed an R-factor of 1.25, an IRR of 11% and a P-factor of 17.00 in a particular year, its share of profit oil would be 50%, because the lowest percentage allocated to the subsoil user is the 50% corresponding to a P-factor of 17.00.
The Tax Code further stipulates that the amount representing the state’s share of profit oil, taxes and other mandatory budgetary payments from a subsoil user in any given year should be not less than 20% of the total value of annual production during years before payback and not less than 60% during years following payback. It is unclear how taxes would be increased if a subsoil user’s total obligatory payments to the state did not exceed the specified minimum value.
The positive feature of the changes is a provision allowing the subsoil user to reduce the state’s share of production under a PSA if a price index declines. However, if the two other factors decline for any reason other than a drop in price, the state’s share cannot be lower than a value fixed prior to the decline in price.
Therefore, the primary feature of the changes to the second tax regime is the flexible sharing of profit oil between the subsoil user and the state, depending on the financial indices of the project and global oil market conditions. The additional taxes on oil and gas companies under a PSA may vary within the following range:
• royalties - from 2% to 6% of the value of oil produced;
• the state’s share of production under a PSA - not less than 7.5%3 of the total after-royalty volume of production before payback; may exceed 45%4 of the total after-royalty volume of production after payback.(The state’s minimum share of production under a PSA before the payback (100%-75%)*30% = 7,5%. The state’s share of production under a PSA after the payback (100%-50%)*90% = 45%)
Recoverable Expenses and Structure of Non-recoverable Expenses
Changes have been made to the Tax Code with respect to the recoverability of costs. For example, a limit on the recoverability of general and administrative expenses was established at the rate of 1% of total recoverable costs. Costs such as social project expenses, one-time fixed payments for the use of the subsoil, commercial discovery bonuses, taxes and other mandatory payments to the budget and some other expenses were classified as non-recoverable expenses. In other words, no cost oil will be awarded for these costs.
Summarizing our analysis, we would like to point out that the introduction of the new tax on exported crude oil and the changes to the rules for calculating excess profits tax and the state’s share of production under a production sharing agreement are designed to increase the state’s income from the mineral resource industry and, in particular, from the oil and gas industry. The tax burden on subsoil users will depend largely on global market prices and the financial measures of each individual project. It remains to be seen how the changes will affect the economics of new projects and the attractiveness of Kazakhstan’s resources to potential investors.
The dominating role of the mineral sector in the Kazakh economy and the dependence of future growth on global market prices currently pose a serious problem. To prevent economic decline, Kazakhstan is taking steps to diversify its economy and stimulate investment in processing, science and advanced technology. Changes introduced to Kazakh tax legislation are intended to promote this process. In addition to tax incentives for companies engaged in priority sectors of the economy determined by the Government, the Tax Code now provides significant tax incentives for companies investing in the oil refining industry and for companies carrying out activities in special economic zones.
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