GLOBAL PETROLEUM FISCAL SYSTEMS COMPARED BY CONTRACTOR TAKE

Daniel Johnston
Daniel Johnston & Co. Inc.
Dallas

Petroleum fiscal terms in most countries are tougher than in the U.S., but these countries have more geological potential and still may be economically attractive.

The market for exploration capital and technology is super competitive and getting more sophisticated. Governments are increasingly aware of the global market for exploration acreage or rehabilitation projects.

Many countries have good potential and know how to compete.

Part of negotiating exploration licenses is knowing the market. Obtaining good terms in the global context is one thing, but nobody wants to negotiate the worst terms in a country even if these are relatively good terms.

For many oil companies, an important part of the negotiations is to secure terms acceptable to the potential partner. Knowing the market and what terms are realistic depends on a region's potential and other factors such as outlined in Fig. 1. Governments do not control the quality of their natural mineral wealth, but they do control their fiscal terms.

Most countries developing petroleum fiscal systems are opting for the production sharing contract (PSC). This trend began in the 1960s. Now, nearly half of the countries with petroleum potential have a system based on the PSC. However, financial results could be the same in a royalty/tax arrangement. Economics depend primarily on division of profits or what is known as government/contractor take.

CONTRACTOR TAKE

Fiscal comparisons center on government/contractor take. Contractor take is the percentage of profits going to the contractor or oil company. Government take is the remaining share.

Division of profits is one of the most important benchmarks for comparing fiscal systems. It correlates directly with reserve values, field size thresholds, and other measures of relative economics.

Detailed economic modeling using cash flow analysis is the best way to evaluate division of profits. Once cash flow is projected, the respective profit shares can be evaluated.

The example calculation box shows a cash flow projection. In this example, gross revenues are $1 billion and costs over the project life equal $400 million.

Total profit therefore is $600 million.

The contractor's profit share is $250 million, or a take of 42%. The government take is 58%.

Besides the profit share, the contractor receives revenues or production for cost recovery. Profit share combined with cost recovery is the total contractor entitlement. In this example, this is $650 million or 65% of gross revenues.

ESTIMATING TAKE

A quick-look approach can estimate government/contractor take without detailed cash flow modeling. This approach has limitations, but most of the time, these estimates do provide useful information.

Often aspects of a fiscal system such as cost recovery limits, investment credits, royalty or tax holidays, and domestic market obligations (DMOs) complicate a quick-look approach. However, an estimate is a good starting point. Most complicating aspects are important but clearly secondary.

The calculation box illustrates a quick-look example of a simple royalty/tax system with a 15% royalty and 40% income tax. 7th subtraction of the royalty yields a net revenue of 85%. Either barrels, dollars, or percentages can be used.

Overall development and operating costs must be estimated. Over the project's life, total costs generally range from 20 to over 40% of gross revenues. This example uses total costs of 35%.

Taxable income is net revenue less costs, and total profit is gross revenue less costs.

The contractor's after-tax net income or share of profits is 30% of gross revenues. Total profit equals 65% of gross revenues. The contractor's 30% share divided by 65% (total profits) equals the contractor take of 46.15%.

Note that the 15% royalty represents 23% of profits. This highlights the importance not only of government take but on how the government extracts its profit share. Fig. 2 further illustrates this concept.

Royalties are regressive because they are levied on gross revenues. For less profitable ventures, the relative percentage of royalty increases. The further from gross revenues that taxes are levied, the more progressive a system becomes.

Government participation occupies a slightly abstract position because usually a government backs in after a discovery, either before or at the development decision. Therefore, at the time of the discovery or back in, government participation behaves much like a capital gains tax.

INDONESIAN SPLIT

The most well known government/contractor take is the Indonesian 85/15% split. An important reason for this is that Indonesia has no royalty.

The split is based on two mechanisms:

A profit oil split of 71.1538/28.8462% in favor of the government.
An effective tax rate of 48%. This results from a double taxation layer of 35% income tax and 20% withholding tax levied after income tax. For the systems analyzed, Fig. 3 shows that Indonesia's fiscal system has the severest terms.

Indonesia's production sharing/tax arrangement has the effect of an aggregate 85% tax rate. The government oil profit share could simply be viewed as another tax.

Because there is no royalty and as long as the contractor recovers all costs, the profit division is virtually the same regardless of costs. This is partly why Indonesia's 85/15% split is widely known.

The example in the calculation box shows the 85/15% split. The calculation assumes 100 million bbl of gross production of which 35 million bbl goes for cost recovery.

Other aspects also impact contractor take in Indonesia. From the exploration and development economics perspective, these aspects are not substantially material. However, once Indonesia's domestic market obligation (DMO) old oil stage is entered, the effective profit division can be closer to 90/10%.

In Indonesia, after producing a field for 60 months, 25% of the contractor's share oil sold to the government receives, depending on the vintage of contract, only $0.20/bbl or 10% of market price. During the first 60 months the contractor receives full market price.

The DMO crude is taxed at an effective rate of 48%. Therefore, Indonesian

DMO sounds awful, but not to an explorationist because many Indonesian fields are capable of producing over 75% of their reserves during the first 60 months.

From a present value point of view, the percentage of reserves not affected by the $0.20/bbl DMO price is even greater. For an explorationist, therefore, the split may be closer to 86%/14%.

TAKE IMPLICATIONS

If a company made a 25 million bbl discovery in Western Australia, it would not be headline news outside Australia. But Australia's fiscal terms are good, over three times better than in Indonesia or Malaysia. The - discovery, therefore, would be equivalent to 80-100 million bbl in Malaysia or Indonesia. The fiscal terms make a huge difference.

The contractor take also directly impacts reserve value. Proved developed producing reserves are worth from one-half to two-thirds of the wellhead price times contractor take. This relationship provides a quick ball-park present value estimate of the contractor's working interest share of proved developed producing reserves. This assumes no major sunk costs available for cost recovery.

Based on a $18/bbl wellhead price, proved developed producing (PDP) working interest reserves in Indonesia are worth $1.101.50/bbl. In the U.S., similar reserves would be worth $4.50-5.00/bbl. These values correlate very closely with the division of profiles.

Economic perspectives differ for exploration, development, and production. Often the exact context must be indicated. For example, when discussing threshold field size, exploration and development thresholds can be significantly different.

Most fiscal system analysis deals with exploration and development economics and to a lesser extent production economics. Therefore, the changing perspectives are a key consideration.

Table 1 illustrates aspects subject to change. Everything is relative. This is particularly true of exploration risk capital and government participation. The explorationist is keenly sensitive to these factors. However, from the development department viewpoint these factors mean substantially less.

For example, exploration risk capital severely constrains explorationists but risk capital often represents an asset for a development engineer. Sunk costs can have considerable value in cost recovery.

Some view government participation as a tax. From the exploration viewpoint this is understandable because Government participation reduces the economic size of a target. However, a development engineer would normally view a government participant as a working interest partner. Therefore, government participation often is not a factor in contractor take calculations.

Government participation was not included in the take calculation in Fig. 3. For reference, maximum government participation is shown on the vertical axis.

For all practical purposes, the government/contractor take characterizes the essence of a country's fiscal severity. Without considering government participation, the average contractor take (Fig. 3) is about 33%.

Royalty/tax systems are generally more lenient but there are exceptions.

When governments must deal with complex geology, high-cost exploration, or limited potential, they can adjust their terms to compensate. Indonesia has done this recently with the new eastern Indonesian terms which are characterized by a 65/35% split. These terms are more than twice as good as the 85/15% split.

Exploration costs in the remote eastern archipelago are substantially greater than in the established provinces around Java, Sumatra, and Kalimantan. Furthermore, the geology is more complex.

To encourage exploration in this region, Indonesia may eventually need to improve the terms even more. But it was a significant change for a country that has a reputation for knowing what the market can bear.

Many countries are reevaluating their position in the global market. The industry is going to see more competitive terms especially in remote, or high-cost areas. And, as areas mature and potential drops off, terms will need adjustment. Governments will focus not only on the take, but also on how the take is extracted. Royalties are going to come down and bonus requirements will continue to be more competitive.

The former Soviet Union and numerous other countries have opened their doors and, thus, increased the size of the oil patch. A more dynamic marketplace will need more balanced fiscal terms and perhaps more adjustments in terms than in the past.

Issue date: 12/12/94