Oil production vs. Transfer Pricing

Oil production vs. Transfer Pricing

The value of crude oil is usually set, for the purpose of both royalties and profit-based taxes, at the point of sale or delivery that is, the point at which ownership passes to a buyer in a sale and at which production is measured for sale purposes.

The point of valuation tends to matter less for oil than for gas and hard rock mining. Upstream and downstream operations are fairly distinct.

Extraction and refining are usually carried out by separate companies. Operations between the point of extraction and point of delivery generally consist of limited initial treatment (removal of water, salt, and other impurities), transport and storage, and marketing.

There is therefore usually no major difference in value at those two points. The costs for example, pipeline fees and demurrage charges are typically limited and relatively easy to quantify. In practice, they are usually deductible for the purpose of natural resource profit taxes, subject to transfer pricing issues if paid to an associate. They may or may not be deductible for royalty purposes, but in most cases, are unlikely to be a major source of dispute either way, as long as the basic rules are clear.

For Albania that export most of the production, the point of delivery tends to be a terminal where oil is loaded onto a tanker. For off shore production, the terminal is often at an off-shore platform where the oil is brought to the surface, sometimes from a number of different undersea wells.

Some production may be delivered to a domestic refinery, in which case the delivery point is a terminal at the refinery.

There may, however, be exceptional cases where costs between the point of extraction (the wellhead) and the point of delivery are significant. In those cases, the alternative approach of assigning the value of oil at a point nearer the wellhead may be adopted.

An example is production in a land-locked country that is transported by pipeline or less commonly by road or rail to a tanker-loading point at a port in another country. This may be the point of delivery, but the transportation costs to that point could be substantial. If the point of valuation is defined as the point of loading into the pipeline, it is necessary to determine the value (or internal transfer price) at that point.

This could be done by netting back the pipeline fees from the sale price at the tanker loading point. These costs would then not be separately deductible for profit tax purposes (which would amount to a double deduction).

Assuming that both the sale at the tanker loading point and the pipeline fees were at arm’s-length prices, this would be a reasonable basis for calculating the internal transfer pricing. It could also be adopted for royalty purposes, if the government’s policy aim is to base royalties on arm’s-length sales value at that point. If the tanker-loading point is adopted as the point of valuation, the pipeline or other transportation costs would usually be deductible for the purpose of profit taxes (subject to any transfer pricing issues if paid to an associate), but again it would be a matter of policy choice whether those costs should be deductible for royalty purposes.

Oil values for tax and royalty purposes are based either on sale prices, subject to a specific transfer pricing rule, or on the basis of general norm or reference pricing. The latter is less common but is used by some major producers, such as Norway. For oil, arm’s-length sales from the same reservoir can reasonably be considered comparable uncontrolled prices for the purpose of the value of non-arm’s-length transactions, because the quality is generally fairly consistent, at least over the short to medium term.

Oil valuation rules are generally based on this assumption and commonly allow for use of monthly or quarterly average prices to increase the pool of comparable uncontrolled prices. If there are insufficient arm’s-length sales from the reservoir to provide a reasonable range of comparable uncontrolled prices in a period, it may be possible to use benchmark prices. These may be used on their own or in conjunction with actual arm’s-length sales of the crude oil to be valuated, and combinations of benchmarks may be used.

There are differences in quality light or intermediate crude oil has a higher proportion of the lighter components, such as gasoline, most in demand, and sweet (low sulfur) crude oil can be refined more cheaply than the sour variety but crude oil from one reservoir is often physically comparable in quality with that from other locations and is priced similarly in commercial transactions. Spot prices for a range of widely traded crude oil varieties are quoted on international exchanges and in publications and databases of organizations such as Platts, which provides the data required for benchmark or reference pricing.

Generally, once a similar quality benchmark crude oil has been identified, standard formulas can be applied to adjust its price to reflect measured differences in its physical quality. Adjustment may also be needed for transportation cost differences, as discussed previously. Benchmark pricing is consistent with standard commercial practice because sales between independent parties are often priced on the basis of a benchmark crude oil with a premium or discount.

If local arm’s-length sales are consistently priced in this way, it may be possible simply to use the standard market premium or discount rather than calculate quality and transportation cost differentials independently.

Inconsistency between transfer pricing rules in production sharing agreements (PSAs) and tax legislation should be avoided.

Usually a PSA article sets out oil valuation rules for production sharing and royalty purposes. It usually contains a specific transfer pricing rule (or in some cases rules for norm pricing), and this is not always reflected in general income tax legislation, which contains only a general transfer pricing rule. PSA valuation rules vary, but they often require arm’s-length sales to be valued at actual sale prices and non-arm’s-length sales on the basis of the weighted average of arm’s-length sales in the month or quarter; if less than half of the oil sold in the period is sold at arm’s length, however, the average price of one or more designated benchmarks, adjusted for quality and transportation cost differentials, is used.

Such specific rules cannot be inferred from a general transfer pricing rule, and could even be inconsistent with it, because average prices may not be equivalent to arm’s-length prices on the date of sale. There is usually no clear policy reason for different valuation of oil sales for income tax and royalty and production sharing, and there are clear administrative advantages to using the same basis.

Disputes about oil transfer pricing should not need to be resolved under different rules for different taxes for no good reason. PSA valuation rules may be applied for income tax purposes as a matter of practice, but as a matter of law PSAs cannot usually override general tax legislation.

Income tax rules should therefore be aligned with PSA rules unless, exceptionally, there is perceived to be a policy reason for them to differ.

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