Understanding the effective royalty rate for new petroleum producing countries

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Bobby Gossai, Jr.
Bobby Gossai, Jr.
Bobby Gossai, Jr. is currently pursuing the Degree of Doctor of Philosophy in Economics at the University of Aberdeen with a research focus on Fiscal Policies and Regulations for an Emerging Petroleum Producing Country. He completed his MSc (Econ) in Petroleum, Energy Economics and Finance from the same institution, and also holds an MSC in Economics from the University of the West Indies. Mr. Gossai, Jr.’s professional experiences include being the head of the Guyana Oil and Gas Association and senior policy analyst and advisor at the Ministry of Natural Resources and Environment.

The investor’s response to any given tax instrument or regime depends on the interrelations that link each of their profit decisions. For example, it may be supposed that a high royalty rate would cause early abandonment of a field and impair resource recovery. Holding all else equal, that is undoubtedly true. But a high royalty may also limit the intensity of the investor’s initial development program, which might in turn cause production to decline at a slower pace, thereby extending the life of the field.

In addition, however, the high royalty may discourage application of enhanced recovery methods as the field matures, and an investor who anticipates this may elect to increase investment in initial capacity as a more profitable alternative to enhanced oil recovery (EOR). The total impact of the royalty on resource recovery, the investor’s rate of return, and government revenues depends on the solution to this set of interrelated investment problems (Smith 2012).

As such, the Effective Royalty Rate (ERR) is seen as a companion statistic to Government Take that helps to show how front-end-loaded the system is. It gives a feel for how quickly a contractor can get its money back. ERR is the minimum share of gross revenues a government will receive in any given accounting period for a field. It typically does not include the National Oil Company (NOC), or oil minister’s working interest share of production. This index has become a standard metric in the industry (and is sometimes referred to in the industry as ‘Minimum Government Take’). It is an important index that adds dimension to the Take statistics.

A complement to ERR – Access to Gross Revenues (AGR) – provides an important international oil company perspective. AGR is the maximum share of revenue a company or consortium can receive relative to their working interest in any given accounting period. It is limited by government royalties, and/or cost recovery limits and profit oil split (i.e. the ERR).

In a Royalty/Tax system with no cost recovery limit, the royalty is the only government guarantee. The ERR is the royalty rate. AGR is limited only by the royalty. In most Royalty/Tax systems in any given accounting period there is no limit to the amount of deductions a company may take and companies can be in a no-tax-paying position (although this can occur with a PSC as well).

Production sharing contracts with cost recovery limits guarantee the NOC a share of profit oil because a certain percentage of production is always forced through the profit oil split. Thus, both royalties and cost recovery limits guarantee the government a share of production or revenues regardless of whether or not true economic profits are generated.

The ERR/AGR calculations require a simple assumption – that expenditures and/or deductions in a given accounting period, relative to gross revenues, are unlimited. Therefore, cost recovery is at its maximum (saturation) and deductions for tax calculation purposes yield zero taxable income. Situations like this can occur in the early stages of production, with marginal or sub-marginal fields, or at the end of the life of a field. The object of the exercise is to test the limits of the system. This provides the ERR/AGR indices.

One key weakness of the ERR index is that it does not measure the effects of depreciation or amortization. It also does not include the effects of the guarantee provided by government participation if and where it exists.

Huge problems can arise if the Effective Royalty Rate is not taken into consideration when designing a fiscal system. Depending on costs and production, contractors could be in a no-tax-paying position for years. This can cause cash flow problems for governments as well as lopsided misperceptions. Typically, this would be an early accounting period following production start-up when accumulated costs are high and production is relatively low (Humphreys et. al 2007).

The Government Participation

Many systems provide an option for the national oil company to participate in development projects. Under most government participation arrangements, the contractor bears the cost and risk of exploration. The government then ‘backs-in’ for a percentage upon discovery. Government participation typically is the result of a government option (through the National Oil Company) to take up a working interest in the event of a commercial discovery. In other words, the government is ‘carried’ through the exploration and appraisal phase in that the government as a working interest partner plays a disproportionately lower share of costs and expenses in the exploration phase than its working interest share. Technically the government through the NOC is carried up to the commerciality point – usually downstream by a well or two from the actual discovery well.

The contract clause that deals with the requirement for delineation/appraisal wells following a discovery is referred to as the “commerciality clause.” The government agent, usually the NOC, must decide whether to exercise their right to back-in once the commerciality point has been reached. Once the government exercises the option it then ‘pays-its-way’ for development and operating costs from the commerciality point forward just like any other working interest partner (Johnston 2006).

Over half of the countries worldwide have this option. Contractors prefer no government participation. This is in part due to efficiency considerations: Joint operations of any sort, especially between actors from different cultures, can have a negative impact on operational efficiency. On the other hand, if done right, such joint operations can be beneficial for governments, both because of the financial benefits and for building capacity.

Government participation clauses vary in terms of how they are structured. The key aspects of government participation are:

  • What percentage participation? Most range from 10% to 50%. This usually defines the upper limit of direct government working interest involvement. The average is around 30%.
  • When does the government back in? This normally happens at commerciality.
  • How much does the government participate? This varies considerably from case to case.
  • What costs will the government bear? Usually, they bear their pro-rata share of costs. However, there is variation in whether governments reimburse ‘past costs’ – those costs incurred by the Intranational Oil Company (IOC) after the effective date of the contract up to the commerciality date when the NOC backs in. About half of the contracts have a ‘past costs’ clause.
  • How does the government fund its share of costs? Often out of up to a certain percentage of the government’s share of production.

The financial effect of a government partner is similar to that of any working interest partner, with a few important exceptions. First, the government is usually carried through the exploration phase and may or may not reimburse the contractor for past exploration costs. Second, the government contribution to capital and operating costs is often paid out of production. Finally, the government is seldom a silent partner.

A key question surrounding the calculation of government benefits from a contract is whether or not government participation should be included in the Take calculation. That is, is this process truly a way by which governments extract rents?

Some analysts believe it is not appropriate to view this element of a system as a rent extraction mechanism on the grounds that such returns are just standard economic returns on investments made. However, this approach contradicts some basic economic laws. And it is easy to check by asking a simple question: “Does the ‘back-in’ cause the foreign investor financial pain?” The answer is a certainly “Yes.” And the pain is multidimensional. First of all, the value of a discovery to an explorer will be reduced by almost exactly the amount of the ‘carry’ and secondly, the companies will not be able to book as many barrels.

A back-in option of 50% is not as costly to the company as a 50% tax on profits (both of which will guarantee the government an added 50% share of profits); but just how different the financial impact depends on profitability and timing. As profitability increases the back-in or participation element takes on more of the characteristics of a pure tax or a royalty, depending on the point at which the government takes its share of production. While it is conceptually a bit abstract, as costs relative to gross revenues approach zero (the ultimate in profitability) the back-in begins to take on all of the characteristics of a tax.

Thus, the less profitable a venture is, the less painful the government participation element is. Either way, both taxes and/or participation options cause the contractor financial pain to various degrees. Hence, to simply ignore the participation element, however, would be a greater misrepresentation. When comparing fiscal terms for exploration rights it is not appropriate to exclude or ignore the participation element. Participation should be considered as a part of the Take for governments.


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