6.1 Forms of State Participation

contribution to the cost of investment due to the slower recognition of expense through depreciation and the lack of an immediate refund for losses.

A simplified APT scheme, not using the RRT already mentioned, has been increasingly implemented with success, generating supplementary revenue to the state when the profitability of projects becomes higher than predefined thresholds. The special tax in Norway, the surcharge tax in the United Kingdom, and the variable CIT rate in several African countries are illustrative.

If properly designed, and when the applicable tax rules are clearly worded with the necessary guidance note, the administration of an APT or a rent-based tax can be not much more demanding than, say, a royalty or an incomebased tax system. It does require the calculation of a specific profit base that measures rent, profits, or cash flows over time, but these data are normally available. As with any tax, detailed accounting procedures need to be agreed on by the parties to ensure that any loopholes or uncertainties in tax administration are eliminated. For countries with limited capacity in their administrations, this is an important consideration, which may encourage them to shift their attention to less ideal but more practical APT instruments. For example, simpler cash flow taxes (such as the special tax in Norway), or APT or production sharing triggered by the economic R-factor indicator (see the subsection “Government’s Share and Taxes under a Production-Sharing Contract” for its definition) are increasingly being applied (Duval et al. 2009, 223–52).

State participation

State participation in EI sector projects may be motivated by nonfiscal objectives, such as knowledge transfer, as discussed in chapter 5. However, as typically structured, state participation in EI sector projects will have a fiscal motivation or tax dimension as well. The motivation is participation in production and profits, especially in their upside potential. The tax dimension depends on how participation is structured. Several forms of state participation can be found in the EI sectors: (1) full participation interest, (2) carried participation interest, and (3) free equity participation (see box 6.1).

With the exception of free equity participation, these forms of participation, full equity participation included, may add little to government revenues relative to the application of an efficient tax regime except when the state interest is high, although they may add considerably to risk by the obligation to contribute to future costs. They usually entail some form of offsetting reduction elsewhere in the fiscal regime, resulting in some equivalence between state participation and tax instruments. (See the discussion of NRCs in chapter 5.)

In each case in figure 6.3, government revenues come overwhelmingly from taxation rather than returns to

Box 6.1 Forms of State Participation

Governments have embraced state participation in their EI sectors in a variety of forms.

1. Full participation interest. The state or its designated national resource company (NRC) invests pari passu with the private sector from the start of operations, by acquiring either an equity share in an incorporated joint enterprise (common in mining) or a participation interest in an unincorporated joint venture (common in petroleum). 2. Carried participation interest. This may take several forms. The most frequently encountered is the socalled partial carry during the early stages of a project. Under this approach, the private investor “carries” or advances the costs of its NRC partner’s interest through specified stages of a project—exploration, appraisal, and possibly even development— after which the NRC spends pari passu with the private investor as under full participation interest. The private investor may or may not be reimbursed for the funds advanced on behalf of the state, with or without interest or a risk premium.

Where compensation does occur, it is typically paid out of the state’s interest in the project revenue. 3. Free equity participation. This option is a simple grant of an equity interest in an incorporated joint enterprise to the state without any financial obligation or compensation to the private investor. The state, however, receives a share in the joint enterprise’s dividends pro rata to its equity interest.

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Figure 6.3 State Participation and Efficient Taxation Compared

18,000

16,000

US$ millions discounted at 15 percent

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Angola

Source: McPherson 2010, 271. Equatorial Guinea Cameroon Guinea Mozambique Timor-Leste

State equity Tax revenues

state participation. Nevertheless, the robust enthusiasm of many governments for state participation, particularly in the hydrocarbons sector, is unlikely to be affected by such considerations. Some investors will continue to favor it too, because participation may help to develop a closer, longterm cooperation with the country.

Withholding taxes on dividends, interest, or foreign subcontractors fees

Given the typical financing requirements of petroleum and mining projects, and their requirements for special expertise and services not customarily available in the host state, dividend and interest payments and subcontractor payments to nonresidents are common and usually significant. Withholding taxes on these payments—amounts that the company is required to withhold from the noted payments and hand over to the state on account of actual or projected tax liabilities of the payees—allows host states to effectively tax this income as there is no practical way to force nonresidents to file returns and account for their incomes. Beyond revenue generation, withholding taxes has the additional advantage of discouraging excessive payments to nonresidents as a means of shifting profits to lower tax jurisdictions (see section 6.5). Withholding tax rates on payments to subcontractors are typically set at relatively low levels, reflecting the fact that they are levied on gross income.14 Treaties may also cap withholding rates in some cases, which is now a major area of base erosion.

Import and export duties

Since there is rarely domestic production of the equipment imported for petroleum or mining operations, the main purpose of import duties in the EI sectors is revenue raising rather than protection of domestic industries. This may be appealing in that it produces early revenues (even before project start-up), but it can also raise costs in the EI sector, lower the profitability of projects for investors, and consequently reduce ultimate tax revenues from EI sector production. Nonetheless, even though duties may be included in costs and therefore result in lower taxes paid, the state still receives more as the deduction is worth only a fraction of the duty paid. Recognizing this, most

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states exempt imports used in an exploration and petroleum field or mine development from duties, either on a specific list or blanket basis, as an incentive to investors. However, inputs at the production stage may or may not be duty exempt.

Both import and export duties are becoming less important as a source of revenue for most countries due to trade liberalization. Most countries have removed export duties altogether; only a few others, such as Malaysia, the Russian Federation and South Africa, impose them on nonrenewable mineral and energy resources. This practice has been driven as much by industrial policy as by any of the fiscal objectives listed, although revenue generation has played a role as well. In a few states, governments introduced export duties with the intention of encouraging investment in domestic processing and smelting capacity. In some cases, where local downstream industry did develop, the duty was probably unnecessary: the high cost of transporting raw minerals usually provided adequate incentive to domestic processing (OECD 2010a). Export duties need to be dealt with carefully because they represent another royalty and as such (1) can be distortive and (2) rather than adding value, may (on a net basis) subtract from it. A legitimate application of export duties will go in pair with an analysis of the competitiveness of the country in the value chain of the downstream processing.

Value-added tax: How to have a workable VAT system for EI activities

VAT is a consumption tax levied as a percentage of the value of goods and services, with VAT paid on inputs credited against VAT paid during the same tax period on domestic outputs. Since the EI sectors are largely export-oriented, they have no domestic output VAT against which they can credit their VAT payments on inputs. Relief for EI sector products when exported must come instead from refunds paid by domestic tax authorities during the same tax period. Given the heavy up-front costs and long lead times characteristic of the EI sectors (including the delays experienced in obtaining refunds in countries with weak administrative capacity), this can pose a serious problem (Boadway and Keen 2010).

Many states, in particular those with a legacy of British influence, have resolved this problem expediently by simply zero-rating (as is the practice for export sectors) the VAT from domestic purchases destined for EI projects (Boadway and Keen 2010). However, care should be taken to avoid creating a perverse incentive whereby imports are duty free and local inputs are taxed to the detriment of local producers. Since the overall economic development aim is to see EI sector development stimulating other parts of the local economy (including the provision of local goods and services where feasible and where this is economic), it is important that these types of perverse incentives are avoided.

Other countries, in particular those with a legacy of French influence, have adopted an alternative approach: to provide VAT exemptions for imported capital goods, specialized services, and sometimes imported inputs. This approach, in Mullins’s (2010, 397) view, is “not considered good tax policy as such exemptions are prone to abuse, complicate administration, and of course, may cost revenue which often has to be recouped from elsewhere in the tax system.” Nevertheless, a specific sector exemption for imported capital goods may be necessary if the tax administration lacks the capacity to administer a refund-based system without any delay. It could be limited by project and in time, and to those goods and services that are necessary to the extractives sector. The overall guideline is that where alternatives to VAT are adopted, these should mimic the correct operation of VAT as far as possible, along with the introduction of appropriate surveillance measures.

Government’s share and taxes under a productionsharing contract

The production-sharing scheme is very commonly applied to oil and gas operations in the developing world, although only very rarely to mining operations.15 In their simplest form, these regimes allow the investor to recover eligible costs through an allocation of production named “cost oil/gas (or cost petroleum)” and share the remaining profit oil/gas (or profit petroleum) production with the government. The government’s share in the profit petroleum is a fiscal revenue scheme for the state similar to sharing profits that can be taken either in kind or in cash, in conformity with the PSC.

There are four main variants of profit-petroleum- sharing mechanisms, each of which is aimed at increasing the government’s profit share on the more profitable projects (IMF 2012, 17b1) to align with the fiscal progressivity objective of the state:

1. Daily rate of production: in which the government share of profit petroleum increases with the daily rate of production from the field or license, often using several tiers. Sometimes this is blended with a scale of prices. Its main weakness is that it is not progressive with respect to oil costs (and prices, except when provided for).

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2. Cumulative production from a project: in which the government share of profit petroleum increases as total cumulative production increases. This is not commonly used. 3. R-factor: in which the government profit petroleum share increases with the ratio of contractor’s cumulative net revenues to contractor’s cumulative investments (or costs in some countries), from the award of the license or contract until the period of sharing (the R-factor). This variant is increasingly used, even if it does not recognize the time value of money, because that mechanism is easier to understand by all the stakeholders than the following rate-of-return approach. 4. Rate of return: in which the government’s profit petroleum share is set by reference to the cumulative contractor rate of return achieved from the award of the license or contract until the period of sharing.

In addition to taking the government’s share in the profit petroleum, the state under any PSC may receive, if so provided, CIT and any other taxes listed in this section, including royalty if applicable and benefits from state participation. Royalty on production is not mandatory under a PSC (Duval et al. 2009, 72): indeed, many PSCs do not provide for payment of a distinct royalty. The reason is that, by design, under any PSC there is already an implicit payable royalty because from the first year of production the state always receives annually a certain government share in the profit petroleum. This results from the applicability of a ceiling percentage rule limiting the portion of production— often significantly lower than 100 percent—that can be allocated under the PSC to annual petroleum cost-recovery purposes. Such a restriction on annual cost recovery does not apply under a tax and royalty fiscal system, in which tax deductions for CIT may reach 100 percent of the taxable revenues, justifying under such system a royalty as a minimum annual payment to the state.

By contrast, CIT is always payable under PSCs as under a tax royalty system, but two alternatives for CIT payment may apply, depending on the PSC wording: (1) either the CIT is directly paid by the contractor or (2) the CIT liability is deemed included in the government’s share in the profit petroleum, which in that case is higher in order to allow the CIT payment by the state on behalf of the contractor (Duval et al. 2009, 246–47). To prevent difficulties and loopholes in assessing CIT liability under a PSC, the country tax legislation must provide for a specific section dealing with the clear determination of the assessable profit under a PSC. In particular, the definition of the eligible recoverable costs and allowable CIT deductions as well as their depreciation rules may be different for the respective determination of petroleum cost recovery and CIT base. Such differences must be clearly stated, as must be the adjustments to be made to the costs jointly recovered by a contractor, to get the CIT deductions of each individual entity constituting a contractor.

Production-sharing regimes share to some extent the pluses and minuses of profit taxes when measured against fiscal objectives. At the same time, some elements of production-sharing regimes, such as the annual petroleum cost recovery limitation, function more like royalties, as explained. Payment of CIT in addition to production sharing allows investors to qualify for a foreign tax credit in their home country.16 The combination of fiscal instruments under a PSC is illustrated schematically in figure 6.4. This overlay of fiscal instruments can create administrative difficulties, which are discussed in section 6.6, “EI Fiscal Administration.”

Angola provides an example of a fiscal package that includes cost recovery, profit petroleum sharing, and CIT liability and excludes royalty payment by the contractor. (See box 6.2.)

Capital gains taxation for transfers of EI interest

Mining and petroleum license, concession, or contract interests and related rights often change hands; they are often sold from one investor to another. This can serve a very useful function. For example, small companies with an appetite for risk may take on EI projects with little appeal to major investors. In the event of success, these small companies (often called “independents” in the petroleum industry and “juniors” in the mining industry) will look for their reward through transfers or sales of their interest and rights to majors with the financial and technical muscle to exploit the discovery. The transaction often involves the sale of shares in companies that hold mineral rights (indirect transfer), rather than a sale of the rights themselves (direct transfer). Such companies are often part of a complex web of cross-border ownership chains. Any capital gain may be made by a nonresident and be protected by a tax treaty.

A large part of the premium, or gains, that independents or juniors achieve on such sales (which may be substantial) is rent; nevertheless, depending on the legislation and regulations in place, the investor may be able to structure the sale so that taxation is limited (for example, by transferring

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