This is a guest post by Harold McClure, a New York City-based independent economist with 26 years of transfer pricing and valuation experience. (One of several that he has written for us.) He considers the issues arising from the Denmark’s Supreme Court's recent ruling in A.P. Møller - Mærsk A/S v. Skatteministeriet.
Denmark’s Supreme Court ruled in favor of the tax authority in its September 6, 2023 decision in A.P. Møller - Mærsk A/S v. Skatteministeriet. This litigation will be discussed in terms of what the oil sector knows as Joint Operating Agreements even if the parties to this litigation did not frame the issues this way. Maersk Olieog Gas A/S (MOGAS) was owned by A.P. Møller-Maersk A/S (APMM) before this Danish affiliate was sold to Total SA in 2018. It carried out preliminary feasibility studies in various parts of the world including the North Sea to find new oil fields, after which entities were established to facilitate the exploration and development, and eventual production of oil. APMM also provided technical and administrative services to other affiliates including Maersk Olie Algeriet A/S and Maersk Oil Qatar A/S.
The Qatar affiliate acted as the operator in the joint exploration and development of oil production operations in Qatar. The Algerian affiliate played a similar role but it contributed no employees and was not involved in the oil exploration projects, the Qatar branch acted as operator. MOGAS issued performance guarantees to the state entities regarding technical and administrative support services. MOGAS incurred expenses for exploration and investigation of possibilities for obtaining licenses for oil extraction. If a license was obtained, expenses were later incurred by the local affiliate. The local affiliate received all income from oil production.
MOGAS did not receive compensation from the affiliates for the preliminary feasibility studies or performance guarantees with the only intercompany compensation being reimbursement for its technical and administrative assistance. The Danish tax authorities said MOGAS had to be considered the owner of the oil exploration license rights and that independent parties would have paid MOGAS a fee equal to 1.7% of the affiliate’s revenues for the use of the licenses. Based on this licensing approach, the Danish tax authorities imposed large transfer pricing adjustments for the years from 2006 to 2008.
The appropriate evaluation of the facts in this litigation represents a challenging transfer pricing issue. We shall argue that while the taxpayer’s position is untenable, the tax authority’s position is not necessarily an appropriate resolution. The OECD Centre for Tax Policy and Administration Secretariat and the Intergovernmental Forum on Mining, Minerals, Metals and Sustainable Development (IGF) recently issued a public consultation document, “Determining the Price of Minerals: A Transfer Pricing Framework.” This framework discussed the roles of exploration, development, and eventual production in the extractive sector. While this framework focused on the mining of metals, much of its discussion applies to the production of oil including:
Prior to the establishment of a mine, there is an exploration process that spans the initial prospecting to the completion of a preliminary estimate of the orebody. The orebody model is then used as a basis to determine whether the resource deposit would be commercially viable to mine. Modern mineral exploration involves the use of advanced scientific techniques to estimate the size and complexity of the mineral deposit, such as sample drilling and geological analysis of mineral quality, and airborne, electromagnetic, and gravitational surveying techniques. Exploration is a high-risk venture. It can be undertaken by companies that specialize in exploration, large multinational companies, or outsourced to service companies that can perform certain aspects of the exploration process. The development phase of the mining value chain involves feasibility studies, mine design planning, and construction. The duration of the development phase varies from months to years and depends on the type and complexity of mine that is being developed. In designing and planning a mine, various commercial options to extract and process the orebody are considered. The design options are then assessed from a financial perspective through feasibility studies to determine whether it will be economical to proceed to the construction and production stages. If the feasibility study and the economical modelling demonstrate that the project would meet the mining company’s internal investment rate of return (or hurdle rate), they are then proposed to the board (both locally and offshore) for final approval.
The general concern noted in this OECD/IGF framework is that the local mining or oil production affiliate pays compensation to its parent corporation for such exploration and technical services that exceed the arm’s length standard. This Danish litigation, however, is a situation where the tax authority for the parent asserts that the intercompany payments fell short of the arm’s length standard. Given the complexity of such issues, the potential for double taxation exists unless the multinational establishes clear intercompany contracts and provides convincing evidence of the arm’s length nature of any intercompany policies.
A Simple Numerical Illustration of Why the Actual Intercompany Policies Were Flawed
Executives in the pharmaceutical sector note the riskiness of R&D in their industry with an analogy to wildcatting in Texas, noting there are many dry holes and only a few gushers. The facts in this case are similar to a classic transfer pricing issue. Imagine a pharmaceutical multinational had the US parent conduct phase I and phase II R&D but then allowed its Irish affiliate to perform phase III clinical trials, production, marketing, and distribution for any successful R&D project. The Irish affiliate would likely generate substantial profits even after incurring all production, marketing, and distribution expenses as well as the cost of phase III clinical trials. The IRS would likely expect sufficient compensation for the expected value of the phase II rights. This compensation might take the form of a one-time payment for the fair market value of the phase II rights or a royalty for these rights. Of course, the Irish affiliate could have paid the UK affiliate all costs plus a reasonable markup if all potential drug explorations whether successful or not were included in the cost pool. While this transfer pricing issue has had a long history, the evaluation of the phase II rights remains a difficult issue.
This oil exploration issue is also a difficult issue. Let’s pose a very simple illustration where there is only a 10% chance of any exploration profit that eventually leads to a successful oil production facility (one gusher and nine dry holes). Let’s also assume that the Danish parent incurs $100 million for each feasibility study. The Danish parent further provided $500 million for the development of any gusher. In any period where the parent performed ten feasibility studies and ultimately helped develop the single gusher, the parent would incur $1.5 billion. Under the intercompany policy, however, the affiliate that ultimately became the owner of the successful oil production facility would pay the Danish parent only $500 million for the provision of technical services at cost. This arrangement would guarantee that the Danish parent would incur losses while the oil production affiliate generates substantial economic rents. The more difficult question would be how to structure an arm’s length compensation arrangement.
Joint Operating Agreements and Potential Arrangements That Would Be Arm’s Length
When the exploration and development of oil and gas properties is carried out by several third party entities, a joint operating agreement (JOA) provides the contractual basis for the cooperative activities. The JOA specifies the financial interests of each party in the agreement as well as their responsibilities under the JOA. The resource owner is often the oil company that ultimately produces and sells any oil or gas once the exploration and development phases are completed. These agreements can vary in terms of the nature of the ownership of financial rights and the contributions each participant is expected to make. JOAs are popular because they provide a way to spread the risk of exploration and drilling. However, they can be very complex.
The taxpayer’s position is similar to paying for phase I and phase II pharmaceutical clinical trials on a cost plus basis but with the two shortcomings we noted earlier. A properly structured cost based approach would have had the affiliates in Algeria and Qatar not only pay for the overall cost of exploration on a probability basis but would also require an arm’s length markup for any development costs incurred by the Danish affiliate. The intercompany charge in this case would have been substantially higher than what was actually paid.
The Danish tax authority noted that MOGAS incurred all costs for researching the oil exploration options and contributed the respective know-how. MOGAS also negotiated the licensing arrangements with third parties. The Danish tax authority asserted that the Algerian and Qatar affiliates should have compensated MOGAS by an intercompany royalty where the rate was set at 1.7% of third party revenues received by the Algerian and Qatari affiliates. The Supreme Court decision noted the basis for the tax authority’s position.
The Ministry of Taxation has submitted to the Supreme Court a benchmark report of 29 August 2022, which contains a database study of royalty rates and licence fees in the oil and gas industry. The report states among other things, that The Tax Agency on the basis of the database study concludes that the market royalty rate between independent parties for as far as concerns "gross sales" is minimum 2%, that the median is 7.5%, and that the maximum is 10%.
This benchmark report appears to be an application of the Comparable Uncontrolled Transaction approach, but the premise that one could find truly comparable third party agreements strikes me as very dubious. A more appropriate approach would extend our analogy to the evaluation of phase II rights in a pharmaceutical R&D issue.
The analysis would begin with estimating the residual profits for the ultimate owner of the third party rights and then consider what fraction of these residual profits were contributed by the Danish entity versus the ultimate owner of these rights. Information on the cost incurred by all participants and the probabilities of success at each stage of development would be required in what would admittedly be a challenging task. A review of other JOAs might provide some light on how these considerations translated into third party arrangements.
While the Danish tax authority might assert that its choice of a 1.7% royalty rate appears conservative in light of its benchmarking report, we should note that royalty rates for phase I and phase II rights in the pharmaceutical sector are often small fractions of the ultimate residual profits for successful drugs. Without a more careful analysis, the tax authorities in Algeria and Qatar could assert that this 1.7% royalty rate was above the arm’s length standard.
If the multinational wished to avoid the complications of properly evaluating an appropriate royalty rate, the intercompany agreements could be structured in the form of a JOA that was based on compensating MOGAS for the fully loaded costs of its contributions to exploration and development. This simpler approach would require that the owner/operator entity had been sufficiently capitalized such that they would have the financial capacity to assume the risk that the exploration activities may have been unsuccessful. The facts in this litigation, however, suggest that the intercompany payments paid to MOGAS fell far short of what would have been arm’s length compensation even under a cost based approach.
 OECD/IGF, “Determining the Price of Minerals: A Transfer Pricing Framework” (May 2023).
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