Where gas is sold as liquefied natural gas (LNG) the point of valuation may be an issue. Gas, like oil, is generally subject to a special tax regime, usually the same one that applies to oil or a modified version.
In Albania, some gas may be sold in the domestic market based in the TAP project, but usually most of gas produced by oilfields can only be exported as LNG.
This means that, unlike with oil, significant local processing costs are necessary before gas is exported because LNG plants are expensive to develop and need to recover their costs. There are broadly two approaches to the taxation of LNG exports:
The aggregated approach: Upstream gas production and downstream (or midstream) operations, including LNG processing, are taxed as a single project. With this approach, there is a single point of valuation for the purpose of any special taxes on gas namely, the point of sale from the LNG plant. Transfer pricing is relevant only to non-arm’s-length sales at that point. However, this approach is not usually recommended given that, as explained, the objective of the upstream fiscal regime is to measure and capture economic rent in the nonrenewable resource. An LNG plant, as an isolated business, constitutes lower-risk infrastructure with no economic rent and therefore should be taxed like any other industrial activity.
The (more common and recommended) segmented approach: Upstream production and LNG processing are taxed separately, with a different tax regime for each. Usually the LNG plant is subject only to general business taxes, although sometimes it enjoys a preferential regime. For the purpose of special taxes on upstream production, gas must be assigned value when it passes to the LNG plant. This approach could include the pipeline as part of the upstream operation or separately.
If there is common ownership of the LNG plant and the gas fields that supply it, or if the owners of each are associated, a transfer price must be established at that point. Governments often, however, regulate the pricing of gas sales to LNG plants. There are various possible reasons for example, to guarantee the plant a sufficient return to encourage investment, to prevent LNG plants from exploiting monopoly buying powers, or to maximize upstream profits subject to higher taxes.
The regulated price may be calculated on a cost-plus basis. It could be a toll designed to give the LNG plant a prescribed after-tax rate of return. All sales to the LNG plant would be calculated on that basis whether they involve associated parties or not. In such cases the government should establish with LNG plant operators which records they must keep and supply on request to show that prices have been charged on the prescribed basis in practice.
Auditing these records requires some technical expertise, but the basis for transfer pricing should not itself be a source of uncertainty or dispute.
Specific transfer pricing rules and average pricing are more difficult for domestic gas sales and LNG exports than for oil. There are some variations in the quality of gas at the point of extraction, depending on the amount of liquids and impurities, but once processed it is a fairly consistent product.
There is nevertheless no standard international spot price that can be used as a proxy for arm’s-length sales values in the domestic market. Spot prices are quoted in regions like the United States and Europe with efficient gas distribution networks and extensive and highly developed infrastructure for domestic gas consumption, but these differ from one region to another and are of little relevance to developing economies whose circumstances are quite different.
Domestic gas prices are in any case often subject to government regulation, so that (just as in the case of sales to LNG plants) transfer pricing is not a factor: all sales are priced on the same regulated basis, whether to an associate or not.
International prices are potentially more relevant to LNG exports, but, whereas the huge growth in LNG international trade is likely to lead to more standardized spot pricing in future, for now there is considerable regional variation based on local supply and demand.
LNG is usually sold under long-term contracts rather than at spot prices. Prices payable under these contracts are usually based on the price on the date of supply of some non-gas comparator in the buyer’s location, such as oil or alternative fuels. Sometimes obligations to take a certain amount of supply (take or pay) are built into the contract.
Transportation costs may be netted back. If an LNG plant sells gas to an associate, for example a related marketing company, it is usually under a similar long-term contract. There is not usually a range of arm’s-length spot price gas sales from the same gas field in the month or quarter that can be used to establish transfer pricing; spot prices quoted elsewhere may not be relevant; and, in any case, use of spot prices is inconsistent with how sales are actually priced in standard arm’s-length transactions.
Although future prices payable under the contract may be based on benchmark prices, all the contract terms and other factors, such as the buyer’s location, must be taken into account in determining whether it equates to arm’s-length terms. Tax authorities must consider whether the comparator used, the length of the contract, break clauses, take-or-pay obligations, transportation cost adjustments, and so on reflect normal arm’s-length terms for sales in the same market. If not, the authorities must ensure that nonstandard variations are reflected in the price. This can be a challenging task, especially when gas is first sold. There may well be no local contemporary long-term gas
contracts on arm’s-length terms available for comparison.
The fact that international gas markets are evolving rapidly with the growth of LNG and unconventional gas adds to the difficulty. Governments may well need external expert assistance.
Because long-term contracts determine prices for years to come, there is a good case for governments to require terms to be approved or agreed in advance if an associate is involved. They should also carry out checks later to ensure that those terms are applied in practice (or modified only with agreement).
Cost Transfer Pricing Rules
A general valuation rule consistent with the arm’s-length principle is not practicable for the total cost of an extractive industry operation. It would likely cause double taxation and tax credit ability problems.
Developing economies often apply cost recovery limits to profit taxes (limiting costs to a percentage of sales), but generally these affects merely the timing of deductions. Albania has considered cost limits for tax purposes, but need yet the clarity about how this would be done in practice.
Countries should, of course, seek to compare their costs against costs in other countries and, where they are higher, establish the reasons and find ways of reducing them. And cost differences for different projects within a country should feature an audit risk assessment. But such differences are common and may have nothing to do with transfer pricing. They may reflect greater physical and technological challenges, higher costs imposed by regulation, or greater perceived risk of providing goods and services to particular countries.
There is, however, some scope for applying specific transfer pricing rules to extractive industry costs. Again practices on this vary significantly from one country to another.
For petroleum, joint ventures are common and impose cost restrictions that give governments significant protection from transfer pricing abuse. An operating company incurs costs on behalf of the joint venture and bills each participant for its share. The other participants’ interests are at odds with those of the operator with respect to shared costs. If an associate of the operator charges excessive transfer pricing, it will reduce the other participants’ profits and the government’s tax.
Joint operating agreements, fairly standard in the industry, therefore incorporate specific fact-based transfer pricing rules. These follow the principle that costs charged by an associate should be at the original cost to the associate. Participants may audit to ensure compliance. Governments cannot necessarily rely entirely on joint venture partners to enforce this no-profit rule, but they can, and often do, build it into PSAs (closely modeled on joint venture agreements) and/or petroleum tax legislation.
The no-profit rule may at first sight seem inconsistent with OECD guidelines, but is in fact the comparable uncontrolled price for costs between non- associated participants in petroleum joint ventures worldwide. Tax authorities then face the issue of how to establish that goods and services were actually provided by associates at cost. They are often advised to negotiate exchange of information agreements with other countries, including tax havens. This is fine in principle, but it is unlikely to be adequate for this purpose.
Instead, audit powers must allow tax authorities to monitor and enforce the no-profit rule. In some cases, general legislation requiring taxpayers to keep records to substantiate their tax returns may be enough, but, if not, specific provisions are needed to disallow costs charged by associates if the taxpayer will not or cannot for any reason show that they were charged at original cost. Or a certificate to this effect from a government-approved
independent auditor may be required. Th e onus of evidence must be on companies.
For mining, joint ventures following the no-profit principle are not common, nor is it standard practice to build this principle into mining legislation and contractual agreements. There may, however, be scope for doing so.
Associates often supply mining goods and services that they brought in from external providers, and it may be reasonable to treat the cost to the group as the relevant comparable uncontrolled price for determining the intragroup transfer price.
An alternative, if inconsistency with OECD rules remains a concern, is to allow a small markup under the cost-plus basis, but governments must be aware that this may make it easy for companies to inflate costs by routing them through tax haven based service companies.
Alternative specific transfer pricing cost rules are possible. One fairly common approach is to limit management service charges to a maximum percentage of total operating costs or total revenues. The percentages used vary significantly from country to country. Although it might be argued that this is consistent with the OECD net transactional method, it is an inaccurate and somewhat arbitrary method of determining arm’s-length prices. It does, however, have the important advantages of clarity and objectivity.
If it is built into legislation or contractual agreements at the outset, then governments can take the generosity or otherwise of the limit into account in planning their overall natural resource fiscal regime, and companies can similarly take it into account in planning whether to invest in the country concerned.
Within limits, therefore, such rules may be acceptable and workable in practice. PSAs often contain standard rules for costing previously used equipment. Again, these may not strictly meet the arm’s-length standard but have the advantages of simplicity and predictability.
Mining and drilling costs charged by associated companies can be very large and present significant risks if there are no clear and specific transfer pricing rules. If the original cost cannot be determined, it may be possible to use standard rates, such as for rental of drilling rigs, but special factors often complicate like-for-like comparisons, and the tax authorities may have trouble obtaining data. For example, the cost of natural resource development may vary considerably across jurisdictions because of different technical demands.
Costs may vary across companies, reflecting different approaches to safety and environmental concerns. Countries with natural resources can benefit from exchange of such data. If it is impossible to come up with specific transfer pricing rules, companies must be required to justify prices charged.
Payments to associates for intellectual property (special processing technologies, technical research, and so on) are less common than in other industries, but not unheard of. Ownership may be located in tax havens.
Pricing is notoriously difficult.