6.4 Main Fiscal Instruments under a Fiscal Regime

There are several downsides associated with RSCs. They transfer substantial risk to the state and, given the lack of performance incentives for a contractor resulting from the embedded service fee mechanism, they may result in significant efficiency losses. RSCs are not popular with investors because of the limited upside return allowed. This may explain why they are found only in states with resource bases that are substantial enough to offset the perceived disadvantages of the arrangement (Johnston 2003, 41, 61).

Fiscal regimes applicable to other EI activities and ring-fencing

Other activities related to oil, gas, and mining—apart from the upstream EI activities related to exploration and exploitation of mines and petroleum fields, which are subject to the specific fiscal systems already described—are liable to the general tax legislation applicable in the jurisdiction at tax rates often lower than for upstream activities. These activities may deal, for example, with pipeline or railway transportation, gas-treating plants, oil storage and terminal facilities for export, liquefaction of natural gas plants, and refineries. The differences in taxation depending on the nature of activities explain why the upstream EI sector is in most countries ring-fenced from the other activities a company may have.

Selecting an appropriate EI fiscal system

In practice, the choice of a fiscal system will turn on contextual considerations such as tradition, political preferences, and existing institutions. Experience suggests that many companies are willing to work with the mentioned systems, whatever their types. There is, however, less enthusiasm for those contractual systems that do not permit them to book reserves under stock exchange rules, such as RCSs, or only a fraction of the bookable reserves under tax-royalty systems, as under PSCs.

A crucial policy consideration is for the government to make sure that the complexity of the design of specific tax rules under a fiscal regime does not outstrip the state’s assessment, collection, and audit capabilities. It is also important that the rules are clear. Three broad approaches are possible. The first is to grow domestic capacity. The second is to limit the complexity of design to the capacity of the tax authority. Third, the country’s own tax staff may be supplemented with experienced international professionals and advisors who are fully able to administer a complex regime. The tax audit capacity is all too often the Achilles heel of the tax administration. Above all, clear and detailed fiscal rules dealing with the specificities of the EI sector must be issued to limit fiscal uncertainties and facilitate smooth implementation of the regime.

6.4 MAIN FISCAL INSTRUMENTS UNDER A FISCAL REGIME

A wide range of fiscal instruments exists and can be found in fiscal regimes applied to mining or hydrocarbons projects. Some are common to all sectors in the economy, such as corporate income tax (CIT), customs duties, value-added tax (VAT), dividend or interest withholding taxes (WHT), employment taxes, income taxes, and capital gains taxation. Others are specific to the EI sector, such as mining or petroleum royalties, resource rent taxes or additional profits taxes, petroleum production-sharing mechanisms, bonus payments, and state participation schemes. In addition, specific EI tax rules may be necessary for each of the abovementioned instruments, such as for tax ring-fencing, CIT rate and depreciation, transfer pricing, carry-forward of losses, currency for tax returns, and so forth. For the investor, the overall tax structure and burden will be critical and more important than the particular tax instruments and rules a government chooses. For the individual government, the various instruments must be selected and combined in ways that fit the context or combination of circumstances. If, for example, there is low capacity or a record of poor governance, a combination of easy-toadminister instruments and limited discretionary power might be warranted. No two countries tax the extractive industries in the same way, which leaves plenty of scope for a researcher to differ on which is best among this “diverse and potentially confusing array of distinct fiscal regimes” (Smith 2012, 3). However, the primary mission of any trusted advisor when assisting a country in its policy is to explain and recommend the recognized best practice and help in designing the most appropriate fiscal package and terms for that country.

Fiscal instruments can be individually evaluated against fiscal objectives, taking into consideration differences among the EI sectors, specific state circumstances, and institutional capacity. However, a fiscal regime uses several fiscal instruments in a combination constituting a fiscal package. The fiscal instruments in a regime interact, meaning that a piecemeal evaluation of individual instruments has limited value. For example, royalties may be a regressive instrument but may well have an important place as part of an overall tax and royalty system. The combination of all the instruments

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and provisions a fiscal regime contains is ultimately decisive in assessing the regime’s likely performance.

With that important caveat in mind, this section reviews the individual fiscal instruments that are typically used. Section 6.5 addresses several related special EI fiscal topics and provisions; it also addresses possible incentives such as tax holidays and accelerated depreciation provisions, illustrating their drawbacks.

Royalty on production

Royalty payments are specific to resource extraction and represent one of the possible means by which the resource owner (the state) is compensated for the permanent loss of valuable, nonrenewable resources. This is the classic rationale for the use of royalties, and the reason why they are not, strictly speaking, a tax. However, the rationale is more likely to be based on the political reassurance that derives from a regular payment and the predictability it adds to government revenue flows. In the literature on royalties, the application of the royalty instrument is, however, surrounded by controversy for both hydrocarbons and mining projects.8

The main type of royalty is the ad valorem royalty (that is, related to the price of the extracted product); in exceptional cases, a unit-of-production royalty (for example, per ton) may apply. Royalties for many metal minerals are generally calculated as a net smelter return royalty. The net smelter return is based on the refined metal price less smelting and refining costs. Payments are received earlier in the life of a project than with other fiscal tools based on profits. They are also relatively easy to monitor and administer. Different approaches to royalty design exist: it may be based on the value of ore at the mine head, on the net smelter return, or on the value of exports after netback for transport and other costs. Royalties for coal or bulk minerals, such as iron ore, are often charged on the basis of the minehead sales price. These are relatively straightforward to calculate. Ad valorem royalty rates are often in the range of 3 to 5 percent for metals and 5 to 10 percent for diamonds (Hogan 2008). Royalty rates are often significantly higher for petroleum production.

Royalties have the advantage for a government in that they are relatively predictable—with the restriction that they are subject to price volatility and production uncertainties— and can help to ensure that companies make some payments to government even in times of low mineral prices and low revenues. The appeal of royalties on gross revenues lies in the early dependable revenue they produce and in their apparent simplicity of administration (Tordo 2007, 37–38). From the start of the producing life of a project, revenue will continue to the end of the life of the field or mine.

The company feels a disadvantage in that the royalties are calculated on production, not profits; a high level of production does not necessarily equate to a high level of profit. A project with high costs could pay as much as one with low cost if the production is the same. The company may have an incentive to prematurely end an ongoing project and not take on one that has marginal production.

The biggest drawback of these two kinds of royalty is in their lack of sensitivity to profit, which makes them regressive rather than progressive and distortionary rather than neutral in a fiscal sense. Where ad valorem or per-unit royalties feature prominently in a fiscal regime, their insensitivity to profit may unduly limit the range of investment projects undertaken and/or cause premature abandonment of production as costs rise and margins fall.

Another drawback is that they are not as easy to administer as is sometimes thought. For example, the valuation of sales can be technically demanding, especially in mining, if the aim is to use benchmarks to reduce the risk of transfer pricing. The establishment of market value at the mine gate or export point can also be difficult, because it involves “net-backing” of costs arising from processing and transportation—for example, from benchmark-refined mineral prices. It may be that no international benchmark prices exist on which to base valuation.9 The most controversial valuation basis for royalty is when the petroleum royalty is assessed on a wellhead value, as in the United States or Australia, and not on an ex-field basis or other agreed point of delivery beyond that location, because there is no way to determine a certain wellhead value, leading to many litigation cases when a wellhead reference is applicable.

The mix of pros and cons regarding royalty has resulted in wide application of royalties in the EI sector but at relatively modest levels. Their importance has been greater in the mining sector than the petroleum sector, where additional profits taxes and PSCs may have been introduced. Some countries such as Chile and South Africa have not used royalties for mining for many years, and in oil and gas production, royalties were favored in North Sea states such as Denmark, Norway, and the United Kingdom but then abolished or reduced to a zero rating where additional profits taxes are in effect. Moreover, many PSCs do not provide for royalty payments.

To better respond to profitability, many countries, such as Armenia, Canada, and Ghana, have introduced more sophisticated forms of royalty, such as a sliding-scale royalty, where the rate is linked positively to production.

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Depending on how rates and triggers are set, these slidingscale tax instruments, common in the hydrocarbons sector but much less so in mining, can be designed to have a progressive tax take. A sliding-scale royalty can also be linked to location. For example, Nigeria has used different rates of royalty, according to whether hydrocarbons production came from land, offshore, or deepwater areas. Other countries have linked progressive royalties to production and price (as in Canada, where the petroleum royalty framework has become quite complex); the date of discovery (existing oil fields and projects or new fields and projects); the nature of petroleum (oil or gas); or some measure of profitability. South Africa uses a profits-based royalty, and so do Peru and New South Wales in Australia. Some countries have also included royalty rates as a bidding item in auctions of rights. Sliding-scale royalties can nevertheless be more difficult to administer, requiring multiple parameters for each mineral. They can also be distortionary, having different effects on different projects.

Corporate income tax: rate and allowable deductions

The application of CIT in the extractive sector is common practice and is a core element in any fiscal system for the sector. However, this is a tax on net income and not directly a tax on effective extractive rents. It is attributable not specifically to the oil, gas, and mining activities but to doing business in the country itself. It ensures that the normal return to equity is taxed at the corporate level in the way that it is in nonextractive sectors. Several countries use a CIT rate for the extractives sector higher than for other activities. Indonesia does this for mining, while Nigeria, Trinidad and Tobago, and many other countries take this approach for the applied CIT rate in their petroleum sectors, in order to stabilize the petroleum CIT rate and avoid being subject to a general CIT rate decreasing periodically, as globally observed in the past two decades. The United Kingdom recently adopted that approach by selecting a petroleum CIT rate of 30 percent while the general CIT rate is lower and set to fall to 17 percent by 2020. Moreover, in many countries the practice is also to design a tailored CIT regime for dealing with issues specific to the oil, gas, and mining sectors. It is better when such a regime remains as consistent as possible with the general tax code rules, with the exception of those fiscal rules specific to the EI sector, which in any case must always be introduced for a smooth implementation of the EI fiscal regime.10

For the government, the appropriate CIT rate for the extractives sector is determined by various, wider objectives. These include whether the government intends to reduce the general rate over time; whether it seeks to obtain a higher CIT rate for this sector than for others; and how it links to other taxes under the fiscal package, such as any additional profits or rent taxation. For the corporate investor, CIT will be assessed in relation to the aggregate tax impact, and especially the effect of tax on its internal rate of return or net present value at a threshold discount rate.

Valuation of production sales for CIT purposes can present problems. Across the spectrum of extractive resources, there are significant differences in identifying a reference price. For bulk minerals, such as bauxite, rutile, and iron ore, and for natural gas, valuation is often hampered by the lack of readily available reference gas prices close to the field. This contrasts with the situation a government faces with the price of oil, gold, and copper, for example. Minerals are sometimes sold on a contract basis, and arm’s length pricing may not apply. The risk that this creates for governments may be mitigated by providing for a detailed EI valuation clause, including determination of arm’s length sales and selection of reference prices, quality, and transport cost differentials.

CIT will usually be applied to the resources sector accompanied by provisions related to the tax base provided for in the legislation. This will typically include a ring-fencing of operations at the project or license level or for the concerned EI sector, precise definition of taxable revenues—value of production and other revenues such as ancillary income, financial income, gains on the disposal of license, or contract interests— and allowable deductions such as depreciation rules, interest, and decommissioning provisions. (See section 6.5, “Special EI Fiscal Topics and Provisions.”)

Signature and production bonuses

Bonuses are one-off (or sometimes staged) payments that may be fixed, bid on, or negotiated and are linked to events such as license or contract award or signature, or to the attainment of a particular level of production. They can be part of any fiscal scheme, provide early revenue, and be easily administered.

Signature bonuses, especially when competitively bid, can be sizeable, and as a result have attracted considerable attention in recent years.11 In 2013 the Liberian National Oil Company announced it had agreed on a signature bonus from Exxon Mobil of US$21.25 million, its largest bonus to date. By comparison, high amounts are common

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in bidding for acreage off the shores of the United States. Much larger amounts can be obtained, however. In 2007 a consortium of Chinese mining companies (CMCC and Jiangxi Copper) agreed to pay the government of Afghanistan a signature bonus of US$808 million and a further US$566 million upon commencement of commercial production. In 2006, Angola received more than US$1 billion as a top bid in its award of petroleum rights.

Bonuses boost the government’s take in situations where there is a concern that other dimensions of the fiscal regime may leave money on the table: that is, collect less than the investor is willing to pay. However, they should not be seen as an add-on to an otherwise comprehensive fiscal regime. While that may be the case, it is more general for investors to seek some offset to the bonus through other elements of the fiscal regime. Essentially, the choice of a specific fiscal tool, such as bonuses, involves trade-offs. Once paid, bonuses are neutral in that they have no effect on investment or production decisions going forward. They provide early revenue, and they are certainly easy to administer.

Investor doubts about the value of signature bonuses in a fiscal regime relate primarily to issues of risk. Where there are concerns about a government’s commitment to honoring fiscal terms, investors will tend to be very wary about paying large sums of money up front on bonuses. This is a sunk cost for companies, recoverable as an allowable CIT tax deduction in the event of successful development of the project only. The fact that it is sunk may increase the political risk if the project turns out to be especially profitable. In practice, many governments continue to rely principally on other, contingent fiscal instruments: that is, instruments linked to actual project outcomes while including up-front signature bonuses as a useful complement.

Additional profits tax or resource rent tax to achieve progressivity

CIT is by nature a tax on assessable annual profits measured as revenues, mostly related to production and price, minus allowable deduction, mainly costs. However, many countries have considered that CIT, although based on profits, does not sufficiently consider their key objective of progressivity in the government take in relation to the achieved rent. For that reason, they have introduced in tax and royalty systems a tax supplementary to royalty and CIT, which is often named additional profits tax (APT), cash flow tax, or resource rent tax or rate of return tax (RRT) and may be triggered by various mechanisms.

Many attempts have indeed been made to link such progressive profit or rent tax to a technical indicator or, better, an economic indicator (see table 6.1). For example, production is an incomplete measure of profitability because it ignores the influence of prices and costs. Price is also an incomplete measure of profitability, because it ignores

Table 6.1 Possible Fiscal Mechanisms in Relation to Government Fiscal Progressivity Objective

Government take is responsive to:

Government take is linked to:

Production

(daily or cumulative)

Reserves/ production

Yes

Oil price change Costs Timing of cash flows Cost of capital

No No Partly No

Price

(price caps or base prices) No Yes No Partly No

Revenue

(price and production)

Cost recovery

(uplifts and write-off rates)

Simple indicators (location, vintage, etc.)

Rate of return

Yes

No Yes No Partly No

No Yes Partly Partly

Partly Partly Partly No

Yes Yes Yes Yes No

Yes

Source: McPherson 2009.

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production and costs, and both indicators ignore the influence of time on profitability. Field or mine location at best may be a very crude indicator of cost and therefore of profitability, but it is likely to be very inaccurate and, furthermore, misses out on the influence of price and production.

Profits taxes, such as CIT, are appealing on neutrality grounds, explaining why they are included in EI fiscal regimes. A project that is profitable before tax will tend to be profitable after tax, because, as long as the rate applied is less than 100 percent, some profit in nominal terms is always left after tax (Tordo, Johnston, and Johnston 2010; RWI 2010). In comparison with other fiscal instruments, profits taxes as CIT also contribute to international competitiveness, since the application of a profits tax is, in critical investor home states such as the United States and the United Kingdom, a prerequisite to obtaining a foreign tax credit (for example, a home country credit for those qualifying taxes paid to the host country).

Profits taxes are sometimes faulted, however, for the following reasons: deferring fiscal revenues to allow for investor cost recovery through depreciation if those are accelerated; being less predictable in outcomes than alternatives such as royalties; increasing the volatility of government revenues (increasing government risk);12 having greater administrative burden related to the need for careful audits of investor costs; and creating incentives for companies to minimize reported profits.

In the extractives sector, several different instruments have been used to capture rent, sometimes with limited success. Natural resource rent has been defined as the excess of revenues over all costs of production, including those of discovery and development, as well as the normal return to capital (IMF 2012). A challenge is to design instruments that capture rent without making projects unsustainable when profitability declines. Governments have therefore developed instruments that are progressive in the sense that they capture an increasing share of revenues as profitability rises. These instruments usually are additional to other baseline instruments such as CIT (and therefore often referred to as “additional profits” taxes). Such flexible instruments to capture rent are more common in the hydrocarbons sector than in mining, but that imbalance is becoming less marked, as mineral-rich countries seek ways of capturing a larger share of the rent without overtaxing the industry during periods of lower profitability.

One way of achieving this is by means of the RRT,13 which “targets the returns made on investments that exceed the minimum reward necessary for capital to be deployed” (Land 2010, 241). It gives an investor relief from RRT taxation until a satisfactory rate of return has been achieved, and after that point, it shares profits with the host government on an ex post basis. Dramatic swings in commodity prices have made the RRT topical as a possible means of collecting what are commonly referred to as “windfall profits tax” or APT. In their favor, it is argued that such taxes do not apply to the normal return in projects, since the government effectively contributes to costs at the same rate as it shares in receipts from production of the resource. As the Henry Report stated, “The government is a silent partner whose share in the project is determined by the tax rate. However, each partner contributes something additional to the partnership—private firms contribute rents associated with their expertise and the government contributes rents associated with the rights to the community’s non-renewable resources. These rents are also shared according to the tax rate” (Henry Report 2010, Ch.1–3).

This resource rent tax based on rate of return was first pioneered in Papua New Guinea in the 1970s but has not yet generated significant revenues to the country. Such schemes have attracted widely varying responses since then. Some reviews are highly favorable, others not so much, deeming the scheme inappropriate and unworkable. It is more common today in oil than in mining, and when used it mainly applies to simplified schemes. Typically, it is assessed on cash flow, a different base than that used for CIT. These bases are quite different: depreciation and finance costs, for example, are not included in the resource rent tax base. In the resource rent tax, when a hurdle rate is passed (on either a before-CIT basis or an after-CIT basis, depending on the structure used), a percentage of cash flow is collected as the resource rent tax. An important consideration for a government in its assessment of any resource rent tax option is the timing of tax payments, because by design the allowances permitted greatly to postpone payments until costs have been fully recovered and the specified internal rate of return on the investment achieved.

Controversy has followed the adoption of some taxes: recent attempts to introduce a windfall profits tax in Mongolia and Zambia were withdrawn in the face of strong resistance from the mining industry. Australia’s first attempt to introduce a resource rent tax in mining brought about the demise of the prime minister. The proposed tax was developed after a government report (Henry Report 2010) called for the introduction of a uniform resource rent tax using an allowance for corporate capital system. This involved a cash-flow-equivalent tax levied on profit measured as net income minus an allowance. The latter was designed to compensate investors for the delay in the government’s

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