Oil And Gas Projects In Kazakhstan
By Kimberly Heimert
New tax rules that took effect in January in Kazakhstan help clarify the tax treatment of oil and gas projects in the country. They also impose more downside risk on foreign investors while shifting upside benefits to the state.
One of the main benefits of the new rules is that almost all of the tax legislation that is relevant to “subsoil users” in Kazakhstan can now be found in one piece of legislation. Previously, investors were forced to look not only in the tax code, but also in a plethora of other legislative and executive acts. (Note that although the amended tax code defines “subsoil users” generally as those who perform subsoil operations, including petroleum operations, this article uses the term “subsoil users” to mean only those who perform subsoil petroleum operations.)
The amended tax code makes it clear that all subsoil users must pay taxes and other mandatory payments under one of two models.
The first model applies to subsoil users that do not operate pursuant to a production sharing agreement. The so-called “Model One” regime requires that subsoil users pay all of the taxes provided under Kazakh law, except for a share of production petroleum. The second model applies to subsoil users that do operate under a production sharing agreement. Unlike in Model One, subsoil users operating under a production sharing agreement are exempted from paying excess profits tax, rent tax on exported crude oil, excise tax on exported crude oil and gas condensate, land tax and property tax. However, such subsoil users also are required to transfer a share of their petroleum production to the state.
The amended tax code suggests that if Kazakhstan’s tax legislation is amended, production sharing agreements may be revised to reflect such amendments, but only upon the mutual agreement of the parties to such agreements. However, it also specifically refers to legislative amendments that “improve the conditions of taxation of a subsoil user” and states that revisions to production sharing agreements “shall be made . . . to restore the economic interests of the Republic of Kazakhstan.” Although not entirely clear, this language is important because it could mean that if the tax burden of the subsoil user is reduced by changes to legislation, the state could require the subsoil user to amend its production sharing agreement to reestablish the prior tax burden of the subsoil user. It is not clear whether such revisions would be contingent on the agreement of all of the parties to the agreement.
Some changes to the tax code affect both the Model One and Model Two tax regimes.
For example, changes to the requirements for bonuses payable by the subsoil user to the state apply to both regimes. As in the past, the amended tax code makes it clear that there are two types of bonuses that subsoil users must pay: subscription (signature) bonuses and commercial discovery bonuses.
Previously, the amount of the signature bonus was established in the relevant agreement and was tied to the economic value of the petroleum deposit. Now, the amount of the signature bonus is determined after the tender process by a commission and is based on the value of the petroleum deposit that is established during the tender. However, it is not clear in the amended tax code whether the value of the petroleum deposit is based on proven, probable or possible reserves or at what price the value should be calculated.
The amended tax code also requires that subsoil users pay a commercial discovery bonus to the state in connection with each commercial discovery they make, unless the subsoil user does not intend to extract the discovered petroleum. The amount of the bonus is 0.1% of the value of the petroleum that may be extracted from such discovery. The value is based on the International Petroleum Exchange of London (or London IPE) prices on the date that the payment is made. The amended tax code does not specify how the volume of petroleum is determined, except to say that the volume should be confirmed by an authorized state body. In the past, the commercial discovery bonus was negotiated between the subsoil users and the state, and the only legal mandate was that it be no less than 0.1% of such value.
The amended tax code also changes the structure and procedure for payment of royalties. These changes apply to both the Model One and Model Two tax regimes. Royalties must be paid by subsoil users based on the value of petroleum that they extract, regardless of whether the petroleum is sold or used by the subsoil user. The value is based on the weighted average realized price for the relevant tax period, excluding all individual taxes and transportation expenses. If the petroleum is not sold, then various procedures are used to determine the value, but, generally, the value is based on either the realized price for the preceding or succeeding tax period or the cost of producing the petroleum.
The new royalty rates vary according to production levels during the relevant calendar year. They are as follows:
For purposes of these calculations, associated gas hydrocarbons are converted into their crude oil equivalent at the ratio of 1000 cubic meters of gas to 0.857 tons of crude oil.
Model One Regime
The Model One tax regime applies to subsoil users that are not operating under a production sharing agreement.
The main changes for such subsoil users are in the rent tax on exports of crude oil and the excess profits tax. Both taxes apply only to subsoil users who do not operate under a production sharing agreement.
The rent tax on exports of crude oil is tied to the value of the exports. This value is based on a basket of published market prices that takes into account sales costs and the quality of the crude oil. The tax rate is determined on a sliding scale based on the price of oil per barrel:
There had been some concern during the debate on the amendments to the tax code that this tax would apply to production sharing agreement subsoil users. However, the amended tax code explicitly exempts such subsoil users from this tax.
The amended tax code also requires that subsoil users under the Model One tax regime pay an excess profits tax on the amount of net income that exceeds 20% of certain deductions. Although this tax is not new, the method of calculation has changed completely. The new excess profits tax rates are as follows:
Model Two Regime
Some of the changes to the tax law only affect subsoil users who are subject to the Model Two regime and, accordingly, operate pursuant to production sharing agreements with a “competent authority” of Kazakhstan.
Under the Model Two regime, the subsoil user retains a portion of the production petroleum equal to the cost petroleum, plus a portion of the profit petroleum (the production petroleum minus the cost petroleum) that is calculated pursuant to one of three formulas provided in the amended tax code. The state receives the remaining portion of the production petroleum.
The formulas that are used to calculate the subsoil user’s share of profit production are based on the R-factor, IRR, or P-factor, depending on which provides the least amount of profit production to the subsoil user and, therefore, the greatest amount to the state.
Under the amended tax code, the R-factor (rate of revenue) is the ratio of the subsoil user’s accumulated real income, less its actual aggregate income tax, to its accumulated cost-recoverable expenditures, each on an accrued basis. The IRR (internal rate of return) is the annual discount rate at which the net present value of the project is zero. The P-factor (price factor) is the ratio of the value of the subsoil user’s cost petroleum and share of profit petroleum to the value of the production petroleum, each during a specific reporting period and each without taking into account certain expenses (such as sales expenses).
The amount of production petroleum that may be allocated as cost petroleum during any reporting period is now further restricted in the amended tax code. In the past, a subsoil user could designate as much as 80% of the production petroleum as cost petroleum. With the amended tax code, that amount is now limited to a maximum of 75% before the subsoil user recoups its capital investment and 50% after such recoupment. Also, the amended tax code makes clear that if there are eligible costs that are not recovered in one reporting period, then such costs may be carried forward to, and paid during, another reporting period.
It also further restricts the expenditures that are recoverable with cost production. For example, taxes and other mandatory payments to the state budget, expenditures that violate local content rules, fines for environmental, technical or safety regulation violations, social programs, and bonuses are not recoverable under the amended tax code.
Finally, the amended tax code requires that the total value of the profit petroleum allocated to the state and the taxes payable to the state during each reporting period may not be, together, less than 20% of the value of the production petroleum before the subsoil user recoups its capital investment in the project, and 60% after this recoupment.
The amended tax code also provides an additional layer of downside protection for the state. It requires that “if the performance of the production sharing agreement conditions becomes worse,” then the state’s share of production petroleum “may not be decreased below its fixed maximum point prior to the worsening of the conditions,” except in certain limited circumstances. It is not clear exactly what this provision means, but it is clear that there is a minimum amount of production petroleum that the state will receive, regardless of the amount of profit petroleum that is produced in any given reporting period.