How to Read and Understand Petroleum Contracts - 6

Fiscal Strategies and Solutions

The previous chapter listed the fiscal tools that governments use with IOCs to share between them the income from a petroleum project. This chapter will describe how these tools are used to create a 'fiscal regime' under a particular petroleum contract.

It is important to remember that there are over 500 different fiscal regimes in use today-- more than the number of countries in the world! Some countries use more than one type of fiscal regime. This results from the different petroleum opportunities that exist in some countries, and the different risks, costs and rewards that may be gained from these opportunities. For example, offshore oil & gas exploration tends to be more expensive than onshore, so the fiscal regime needs to be adjusted to reflect this. Natural gas projects have a different price, cost, regulatory and operational environment, so fiscal terms for gas typically are more generous to the IOC than for oil.

We're going to give away the conclusion right now: there is no single system that is the right one for every situation. There are wide differences in geological prospects, reservoir conditions, costs, prices, infrastructure and availability of services. Attractive investment opportunities can exist in each jurisdiction, and a fiscal system that works in one jurisdiction may not work in another.


So where to begin when creating, reviewing or evaluating a fiscal regime? Let's remember that the objective is to share the divisible income (project revenues minus project costs) between the state and the IOC. One approach is to ask a series of strategic questions about the goals the state wants to achieve, and then to use the appropriate fiscal tools to achieve those goals. Here are four key questions that can help a state to define its strategy:

  • how should the fiscal regime treat changes in the profitability of petroleum operations
  • what is the timing of the state's share of the divisible income?
  • how much risk of success of petroleum operations is the state prepared to take?
  • to what extent does the state want to encourage initial petroleum investment and re-investment?

We will examine each of these issues individually.

Changing Profitability

The fluctuation of petroleum prices, costs and production rates means that the profitability of oil & gas operations changes over time. Fiscal systems can react to these changes in one of three ways. A regressive fiscal regime gives the state a lesser share of revenues when profitability increases. A neutral fiscal regime gives the state the same share of revenues when profitability increases. A progressive fiscal regime gives the state an increasing share of revenues when profitability increases.

It is important to stress that these are not value-judgements on the fiscal regime.  To say a state has a regressive fiscal regime is not to say that is it old, antiquated and out of touch with modern reality.  There may be good reasons for a country to choose regressive fiscal tools that result in a regressive system.

Understanding Regressivity and Progressivity 

A few examples may be useful to illustrate these effects. The first addresses a production bonus.

EXAMPLE: In the Libyan petroleum contract described in the previous chapter, the IOC pays a bonus of $5,000,000 when 100,000,000 barrels of oil equivalent is produced.  Whether that oil is sold at a price of $50 per barrel or $100 per barrel makes a big difference to the IOC's profitability of the project, but the government's revenues from the production bonus is unchanged by this fact. The IOC is required to pay the bonus, regardless of whether its operations are more profitable or even unprofitable. So, a production bonus of this type is regressive.

A fixed royalty is another case in point.  

EXAMPLE: In the US Gulf of Mexico case mentioned earlier, where a 16.67% royalty applies in shallow water, the government receives one-sixth of oil produced. If the price of oil goes up, oil & gas operations almost always become more profitable, because costs tend not to increase in precisely the same proportion. However, the government receives the same one-sixth share of production regardless of the price increase. While the government's share is more valuable because the price is higher, it will in fact represent a lesser share of the profitability of the activity in most cases.

Corporate income tax is a neutral fiscal tool, because the tax is applied to a corporation's net income (or profit). The tax rate is the same, regardless of whether that profit is large or small. Fixed percentage profit sharing works the same way-- it is also a neutral fiscal tool.

An example of a fiscal tool that increases the state's share of profits when profitability increases is an R factor royalty or profit share.  In the Azerbaijan example in the previous chapter, the government's share of profit oil increases from 15% to 35% as R goes from zero to two. When oil & gas operations become more profitable, the R factor increases more quickly, and the state's share of profits increases.  This is an example of a progressive fiscal tool.

A fiscal tool can be regressive, neutral or progressive with respect to the three key factors of petroleum profitability, which are price, costs and production rate. A sliding scale royalty that increases as the production rate goes up is a progressive feature in terms of production, but not for price or cost. A sliding scale based on the price of oil would be price-progressive but not cost or production progressive.  Sliding scales using R factors or internal rate of return focus on overall profitability, and therefore they tend to be progressive across all three features.

[Insert prepared graphic about progressive, neutral and regressive]

Approaches to Profitability

The question of what approach to profitability should be adopted by a state is an interesting question.  Historically, the most common types of petroleum fiscal tools are bonuses, rentals and fixed royalties, which are regressive.  But governments typically prefer to tax corporations in all areas of endeavour on a neutral basis, and individuals on a progressive basis.  So taxing IOCs on a regressive basis seems unusual when compared to other citizens, corporate or individual.

Moreover, the fluctuating profitability of the oil & gas industry is bound to lead to situations where an IOC's operations become very profitable at some times during the long term of a petroleum contract.  States tend to be irritated when IOCs profits go up while the state's share of those profits go down or stay the same.  This fact is one of the reasons why states often change the fiscal regime during the term of an investor's operations, leading to instability and friction between state and IOCs.

Creating progressive fiscal features that give a state an increasing share of profitability is one way that this area of potential friction can be addressed.  If a suitably progressive fiscal system exists, then a state should be pleased when oil industry profitability goes up, because the state's share of those profits will also go up.

Two notes of caution are in order when dealing with this approach to profitability.  First, oil industry profits don't always go up; prices and costs go up and down.  There are times when an IOCs activities may be unprofitable.  If a state's share of revenues drop to zero in such circumstances, that can also be irritating to a state, and the state may not be readily able to deal with such an absence of revenue.  So, there is a strong case to be made for regressive fiscal tools that generate government revenue whenever oil & gas is produced, and regardless of whether the activity is profitable.

Second, a fiscal regime that takes away too much of an increase in profitability can result in a situation where this acts as an incentive to increase costs.  Economists refer to this behaviour as 'gold plating', because the IOC has an incentive to incur excessive costs (such as an imaginary plating of the facilities in gold) or no incentive to reduce costs.  A regime can be tested for its goldplating by the use of a financial model; if an increase in costs by a dollar results in government revenues reducing by more than a dollar, then it's a goldplate. Such regimes may also create incentives to the IOC to reduce the production rate or sell production at a discounted price, which have similar effects as goldplating.  

Goldplating results in a misalignment of the interests of the state and the IOC.  Fiscal systems work better when the IOC has a financial incentive to achieve the same result as the state, which generally is to increase production at the highest price and the lowest costs. 

Most states choose a variety of fiscal tools resulting in a hybrid system. When creating, reviewing or evaluating a fiscal regime, it is important to recognize the potential impacts of each tool in an environment where profitability frequently changes.  

Profitability and the Fiscal Tools

Now that we understand the concepts of regressivity and progressivity, and the state can decide how it wants to approach this issue, we can assess which fiscal tools to use.  Here is a list of the fiscal tools described in the previous chapter, and whether they are regressive, neutral or progressive:

  • signature bonus: very regressive
  • production bonus: very regressive
  • fixed royalty: regressive
  • sliding scale royalty: progressive
  • corporate income tax: neutral
  • fixed profit share: neutral
  • sliding scale profit share: progressive
  • state participation: neutral
  • profit-based taxes: progressive
  • other general taxes: varies, but generally regressive
  • service fee systems: very progressive

[graphic - progressivity and regressivity of six individual fiscal tools]

Timing of Petroleum Revenues

Each of the fiscal tools described in the previous chapter provides revenue to the government at a different point in the lifetime of a petroleum project.  A signature bonus is payable at the time the petroleum contract is signed, before production begins (and before it is even known if there will be production).  A production bonus may be payable at the time that production begins and then at various times during the production phase.  Corporate income tax is payable only once the IOC is making a profit, which usually means that it will need to have recovered all of its costs.  IRR-based fiscal tools tend to generate the most income only after the IOC has earned a good rate of return.

So each of these fiscal tools can be said to be: 

  • 'front-end loaded', which means that they begin to apply before the IOC has recovered its costs (in other words, the state receives revenue before the IOC is making a profit)
  • 'neutral', which means that they apply only upon the IOC recovering its costs (so the state profits only when the IOC profits)
  • 'back-end loaded', which means that the state's share only becomes significant after the IOC is in a profitable environment

The state typically chooses the fiscal tool based on when it wants to receive the petroleum revenue.  Naturally, states want money sooner rather than later, but IOCs would rather pay money later in the life of the project once profitability has been established.  Consequently, this is a balancing exercise.  The more that is required to be paid up front, the less can be expected as the back end, and vice versa.

There are certain parameters that help to understand the choice of the fiscal tool, but these are not included in the petroleum contract.  One such parameter is the  'discount rate' of the government and the IOC.

EXAMPLE: A poor government that has a very high need for money today probably has a high 'discount rate': it would prefer to have $1.00 of revenue today rather than $1.20 a year from now, an effective discount rate of over 20%.  A rich government that has the ability to borrow funds at attractive rates probably has a low discount rate, so if you offered it $1.05 a year from now, it would prefer that over $1.00 today, resulting in a discount rate of less than 5%.

IOCs have discount rates too, generally in the 10-15% rate or higher, because they can put today's dollar to use to generate a profit in a year's time. So, in the balancing exercise involved in choosing the timing of the revenue, logical behaviour would be for wealthy governments to back-end load their fiscal regimes, and poor governments to prefer to front-end load. Sometimes this logic prevails, but often it does not; for example, the wealthy province of Alberta, Canada has a system that prefers up-front payments, while Papua New Guinea has a back-end loaded system.

Here is how the fiscal tools fit into the timing scenario:

  • signature bonus: front-end load
  • production bonus: varies
  • fixed royalty: front-end load
  • sliding scale royalty: varies
  • corporate income tax: neutral
  • fixed profit share: front-end load to neutral (depending on cost oil limit)
  • sliding scale profit share: neutral to back-end load
  • state participation: neutral
  • profit-based taxes: back-end load
  • other general taxes: varies

Service fee systems are not as easily categorized because the government pays the contractor a service fee retains all the revenues. The impact on the state and the investor varies with the service fee system that is chosen.

Risk for the State

IOCs generally bear the risk of success or failure in petroleum operations. Managing and bearing exploration risk, capital cost risk, operating cost risk and commodity price risk is their stock in trade. The issue for states in designing their fiscal regime is, how much of this risk is the state willing to share?

A state could choose to take no risk of petroleum operations by selling to an IOC the land on which petroleum operations are to occur for a defined price, without any royalty or other future payment obligation. The state's share would be unaffected by exploration success or failure, oil price fluctuations, production rate fluctuations and changes to the cost environment.However, no state takes this approach to petroleum activities. Every government designs a fiscal system that will capture some of the economic rent of a successful petroleum project. But the design of the fiscal system can affect how much of the risk of success or failure that the government is prepared to share with the IOC. For example, if a government receives a fixed royalty of 12.5%, the state does not share in the cost risk of petroleum operations: it will receive one-eighth of production, whether the IOCs operations are profitable or not. An IRR-based profit oil share will result in the government sharing all of the risks of the IOC's success, because it will receive a significant share of production only after the IOC has profited. Some states make it a strategic national goal to have a direct involvement in petroleum operations through the participation of a state oil company. This involves sharing most or all of the risks of petroleum operations. The extent to which a state bears the risk of success can have an impact on other features of the petroleum contract. If the state shares in the cost risk (for example, through a state oil company participation or a profit share), then the state may want a greater operational or approval role in the costs that the IOC plans to incur, such as a joint management committee.Here is how the various fiscal tools stack up for state risk sharing for exploration, production rate, price risk and cost risk:

  • signature bonus: no risk
  • production bonus: exploration risk only
  • fixed royalty: exploration risk only
  • sliding scale royalty: exploration risk, and some or all of production risk, price risk and cost risk (depending on the sliding scale factor)
  • corporate income tax: full risk
  • fixed profit share: full risk
  • sliding scale profit share: exploration risk, and some or all of production risk, price risk and cost risk (depending on the sliding scale factor)
  • state participation: no exploration risk; all other risk
  • profit-based taxes: full risk
  • other general taxes: varies
  • service fee systems: full risk

Encouraging Initial Investment and Re-investment

States typically are seeking to encourage IOCs to invest in petroleum exploration, so that oil & gas can be discovered and produced. The decision of the IOC on whether to invest is a function of the attractiveness of the geology in the block that is on offer, and the attractiveness of the fiscal regime. This issue needs to be analysed in two ways: initial investment (or 'stand-alone' investment) and re-investment.

Some fiscal regimes are better structured than others to make initial investment attractive.  A big signature bonus is a disincentive to invest, because it requires the IOC to pay up front for the right to explore, before it knows if the block has commercial reserves. The funds that the IOC has available to conduct exploration are reduced; maybe the amount spent on the signature bonus could have been spent on an extra well that might have been a success. Conversely, a production sharing contract with a high cost oil limit means that the IOC can recover its exploration costs (including unsuccessful wells that precede a discovery well) before the state share of revenues becomes significant.

Some petroleum contracts will result in IOCs investing in a state for the first time, and they analyse their interest in doing so by assessing the attractiveness of the fiscal regime on a 'stand alone' basis. However, most petroleum investment that happens in the world is in activities by an IOC in a state where they already have petroleum operations, often in a different block.  In such cases, the IOC will assess the fiscal regime on the basis of its overall impact on its existing and new investment. This is important because sometimes IOCs are able to deduct the costs of a new investment against the revenues and taxes paid on an existing field. This makes re-investment more attractive. An example might be useful here.

EXAMPLE: If an IOC has petroleum revenue in a state on which it is paying income tax at 35%, and the cost of an exploration well is deductible in calculating income tax, then the after-tax cost to the IOC of drilling a new $10,000,000 exploration well in that state is only $6,500,000. While the state suffers a reduction in its tax revenue as a result, the incentive for the IOC to re-invest in that state is significant. Success often begets success, so the IOC is likely to develop a larger business in that state, generating more government take, and will prefer to re-invest there rather than looking abroad.

This kind of re-investment incentive happens when the fiscal regime is 'consolidated' rather than 'ring fenced'. Ring fencing was discussed in the previous chapter. Ring fencing tends to reduce the incentive to re-invest, while consolidation tends to increase it.

The various fiscal tools have the following impact on investment and re-investment: 

  • signature bonus: disincentive to invest and re-invest (unless deductible against fiscal term)
  • production bonus: neutral
  • fixed royalty: disincentive to invest and re-invest
  • sliding scale royalty: neutral on incentive to invest; reinvestment impact depends on ring fence treatment
  • corporate income tax: neutral on incentive to invest; strong reinvestment incentive depending on ring fence treatment
  • fixed profit share: neutral on incentive to invest; strong reinvestment incentive depending on ring fence treatment
  • sliding scale profit share: neutral on incentive to invest; reinvestment impact depends on ring fence treatment
  • state participation: disincentive to invest; reinvestment impact depends on whether state oil company is carried on the subsequent investment
  • profit-based taxes: neutral on incentive to invest; reinvestment impact depends on ring fence treatment

State Participation

A state's right to participate in oil & gas operations is frequently used and has both socio-economic and fiscal impacts. Some of these fiscal impacts are not always clear, so further explanation is worthwhile.

State participation has the following results on the four strategic considerations:

  • Changing Profitability: neutral
  • Timing: neutral
  • Risk: no exploration risk (where carried); all other risks
  • Initial Investment and Re-investment: disincentive to invest; reinvestment impact depends on whether state oil company is carried on the subsequent investment

The state's share of profits will be the same as the IOC's share because the state oil company's participating interest share typically is a co-investment by the state oil company and the IOC. For the same reason, the timing of the state's share of revenues is neutral as well.

Except for a 'full equity' state participation, the state does not bear exploration risk, because the typical state participation right is an option for the state to participate at the time of a commercial discovery. If exploration is unsuccessful, then the state does not participate, and the IOC bears all the cost of failure. If exploration is successful, then the state will elect to participate.

This is a very attractive feature for the state-- it's a risk-free bet on exploration success. Some states like this so much that they seek to increase this as a feature of the fiscal regime. The problem is that, depending on the percentage of carried participation, it can have a seriously negative impact on the attractiveness of the initial investment by the IOC. Let's use a simple example to explain this.

Let's imagine that you are entering a casino to play roulette, and the owner offers you a deal. Admission to the casino is free if you'll agree to give to the owner five percent of every winning bet you make. You need to make a decision: are you a good enough gambler to be able to afford to give up five percent of your winning bets, while bearing all of the cost of your losing bets? Perhaps you are, and you enter the casino and play for the day. The next day, the owner offers a different deal: free admission to the casino costs fifty percent of every winning bet.  Now your decision is quite different. Paying for all of your losing bets while giving up fifty percent of the winning bets is too risky; there's not enough reward left to justify the risk.  It's time to find another casino.

State participation rights work in a similar way. The economic impact to the IOC of a carried participation affects what the economists call the 'maximum sustainable risk'. If you take away too much of the exploration incentive, it's simply not worth playing the game. This is why a carried interest for the state is a disincentive to invest, and the larger the carried interest, the greater the disincentive. It is also a disincentive to re-invest if the state oil company is also carried on the re-investment activities. Nevertheless, this is a fiscal feature that more states are adopting.


Now that we have surveyed the strategic issues and the impact that various fiscal tools have on those strategies, let's look at some possible objectives that a state might have and analyse the how the fiscal tools should be used to attain those objectives. The following analysis is also useful for readers of a petroleum contract to assess the extent to which a particular petroleum contract is suitably designed for its stated objective.

Promoting Exploration

If a state wants to encourage exploration activity, the fiscal package should involve the following features:

  • low or no signature bonus
  • low rental during exploration phase
  • full deductibility of exploration expenditures under corporate income tax
  • high cost oil limit in production sharing contract
  • avoid carried interests for state participation

Promoting Cost-Effective Operations

Some states prefer a profit-based taxation system that is progressive and back-end loaded.  What they often find is a result where IOCs incur high costs. If a state wants to encourage cost-effective operations to maximize profits, the fiscal regime should:

  • avoid IRR-based sliding scales
  • avoid R-factor systems with high marginal tax rates on profit oil
  • avoid uplifts where the IOC is entitled to a deduction of greater than 100% of any cost

Also, service contracts tend not to promote cost-effective operations, because the IOC has no financial incentive to minimize cost under most service fee structures.  

Marginal Field Development

Some states need to manage production from marginal fields or petroleum basins that are mature. The following fiscal tools are appropriate: 

  • use sliding scale royalties based on production rates
  • allow high depreciation rates for development costs
  • allow full consolidation for corporate income tax
  • avoid high fixed royalties
  • allow high cost oil limits (or none at all)
  • utilize IRR and R-factor systems

Gas Development

The economics of gas exploration and development tend to be less attractive than for oil. Development costs are typically much higher, and production prices are generally lower.  However, many states treat both types of resource in the same way, and gas development is stunted. The following fiscal features can help:

  • lower royalty for gas
  • high depreciation rates for corporate income tax on gas pipelines and other facilities
  • high cost gas limits, lower profit gas share for the state
  • exempt gas projects from special taxes
  • exempt gas projects from carried state participation


When conducting petroleum operations, it should come as no surprise that IOCs tend to behave in a manner that is consistent with their economic interests as established by the fiscal regime in the petroleum contract. Therefore, it is important that the fiscal regime is designed so that it encourages IOCs to act in a manner which is consistent with the objectives of the state. Unfortunately, many states create fiscal regimes that encourage behaviour by IOCs that is inconsistent with what the state wants to achieve.

Service contracts are particularly challenging in this regard. States want more oil production at lower cost and higher prices. Yet service contracts tend to create structures with minimal incentive to the IOC to increase the production rate, and no incentive to keep costs low.

The same situation arises in other types of petroleum contracts where the fiscal regime is excessively progressive. This leads to distortions in IOC behaviour; there are examples where under certain conditions a petroleum project may be more profitable with higher costs than with lower costs, or the incentive to reduce costs is so minimal that the IOC tends not to do so.


Some fiscal tools call for greater administration resources than others. A fixed royalty tends to be fairly easy to administer; a fixed percentage of production is owed to the state. All that is required is a meter at the relevant delivery point to determine the state share. If the state does not take its share in kind at that point, then the IOC accounts to the state for the revenues it receives for that share.

Production sharing contracts tend to involve a higher degree of administration, because the state needs to be concerned about costs. Authorizing expenditures, accounting for costs and auditing IOC activities are now required.  

State participation adds another layer of administration. The state oil company as a co-contractor now is also involved in approving activities and expenditures, accounting and auditing. 

For states that have the technical, administrative and financial capacity to administer complex systems, these structures may make sense.  For those states who do not, a better approach may be to keep administration simple.

The Shift to Non-Conventional

There is a significant movement in the petroleum industry in the past decade that is resulting in growing focus on 'non-conventional' petroleum resources.  This has the potential for significant change in petroleum regimes and contracts.

'Conventional' oil & gas is found in subsurface reservoirs of porous rock where petroleum is 'trapped' by the surrounding geology.  As the world's conventional oil & gas resources are becoming more scarce, IOCs are focusing more on developing and producing oil & gas from 'non-conventional' (sometimes called 'unconventional') sources.  

This means oil & gas produced or extracted using techniques other than the conventional  methods. Non-conventional oil & gas production is a less efficient, more expensive process and often has greater environmental impacts than conventional oil & gas production.

One way to look at this shift to non-conventional is to compare conventional petroleum resources to the best parts of a cow.  (Apologies to vegans and Indians).  

Conventional oil & gas is like the tenderloin and sirloin-- it's the 'steak' of the petroleum cow.  It is comparatively easier and less expensive to find and develop, and it's the tastiest part too.  However, just as we eat other parts of the cow, there are other parts of the petroleum cow that can produce oil & gas too.  Shale gas, coalbed methane, oil sands, ultraheavy oil can also be produced.

However, just as the brisket and shank of a cow cannot be cooked like a steak, we need different 'recipes' to make the rest of the petroleum cow attractive.  Different fiscal terms are required in order to make attractive these more costly, and often less valuable resources.  Also, different tenure regimes are often required.

This is the trend in advanced petroleum states today.  The province of Alberta, Canada has five different fiscal regimes to make investment attractive for its conventional oil & gas, oil sands, heavy oil, coalbed methane and shale resources.  Other states are following this trend.

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