The offshore oil and gas drilling industry is made up of drilling contractors (the owners and operators of drilling rigs) that provide services for drilling oil and gas wells. The industry is subject to intense price competition and volatility, and periods of high demand and higher day rates are often followed by periods of low demand and lower day rates. The market for drilling services is substantially affected by global hydrocarbon demand and changes in actual or anticipated oil and gas prices. Furthermore, sustained high energy prices may translate into increased exploration and production spending by oil and gas companies, which can in turn lead to increased drilling activity and demand for rigs. However, weakening oil prices through 2015 have slowed new investment in offshore drilling projects.
Customers in the industry have been demanding higher efficiency rigs, which requires newer rigs be built to greater specifications. Evidence of this trend is demonstrated by higher utilisation of rigs with increased specifications, and lower utilisation rates for conventional drilling rigs. In particular, the demand for high-specification rigs has led to an increased demand for drillships that operate in deep water and ultra-deep water, and are equipped with the latest dynamic positioning systems.
Overview of bareboat charters
As part of the competitive and legal environment in which offshore drilling contractors operate, one approach taxpayers have taken is to separate ownership and the operations of drilling vessels in different tax jurisdictions. Under this structure, a rig owner in one jurisdiction receives payment for use of the vessel by local operating companies in the customer's tax jurisdiction. The local operating companies may have employees who operate the drilling vessels that are provided by foreign related-party rig owners. The term for this payment by the local operating company to the rig owner for use of the drilling vessel is a bareboat charter (BBC).
The price of the BBC given the terms and conditions of the related-party transaction, is a transfer pricing question that continues to generate significant global debate between taxpayers and tax authorities. The amount of capital required to construct drilling vessels is one of the most significant burdens placed on the consolidated drilling company. The asset owner bears (either directly or indirectly) the cost of that capital, and economic principles provide that the return on those costs should be commensurate with the amount of risk incurred. Taken together, these facts argue for a significant return being earned by the asset-owning company. Conversely, most if not all of the employees are located in the operating companies that (either directly or indirectly) contract with the customer, utilise operational skills, and ultimately execute projects for customers. Tax authorities may argue these contributions by the local operating companies constitute valuable intangibles, or alternatively, are valuable services that deserve a much higher return than that paid by the local operating company.
The repercussions of the Deepwater Horizon event of April 2010 still linger, raising questions about how significant a role uninsurable liability risk plays in the offshore drilling industry, which of the related parties bears the risk of those liabilities, and how those liabilities should be accounted for in the transfer pricing analysis. Furthermore, in addition to the observable economic contributions of the related parties (such as drilling vessel, employees, etcetera), taxpayers may structure intercompany arrangements that shift market or other types of risk to certain related parties. Accurately accounting for this array of risks, and quantifying them in addition to other observable contributions in the transfer pricing analysis can present great challenges for taxpayers.
Current events in US
Public disclosure of the BBC issue is largely limited to analysis of SEC filings and documents from one US court case. In that case, the Internal Revenue Service (IRS) ultimately conceded the transfer pricing adjustments, and a January 12 2012, stipulation entered by US Tax Court Judge James S. Halpern stated that "after taking into account self-initiated adjustments reported on that return, reflects arm's-length transfer prices, pursuant to Section 482…for payments made to certain of its foreign affiliates in 2004 pursuant to bareboat charters of drilling rigs owned by those foreign affiliates".
Subsequent to that case, in 2014 the IRS again issued assessments "related to transfer pricing for certain charters of drilling rigs…This item, if successfully challenged, would result in net adjustments of approximately $290 million of additional taxes…" Clearly, the issue continues to be of interest to the IRS.
There is no information in the public record as to whether any taxpayers have concluded advance pricing agreements (APAs) with the IRS in relation to BBC transactions.
Transfer pricing methods
A traditional method used to price BBCs involves using publicly available results for third-party service providers engaged in similar technical services as those performed by the related-party operating company.
Typically, to determine the BBC amount, a mark-up on costs is derived from third-party service providers and applied to the uncontrolled costs of the operating company. The difference between the third-party revenue and the marked-up uncontrolled costs is taken as the BBC payment.
The term "uncontrolled" used above is deliberate as it is well established practice that controlled expenses are not part of the cost base. While US transfer pricing regulations do not specifically explain this idea, the OECD guidelines express it as follows:
"The denominator should be reasonably independent from controlled transactions, otherwise there would be no objective starting point. For instance, when analyzing a transaction consisting in the purchase of goods by a distributor from an associated enterprise for resale to independent customers, one could not weight the net profit indicator against the cost of goods sold because these costs are the controlled costs for which consistency with the arm's length principle is being tested. Similarly, for a controlled transaction consisting in the provision of services to an associated enterprise, one could not weight the net profit indicator against the revenue from the sale of services because these are the controlled sales for which consistency with the arm's length principle is being tested."
Furthermore, the IRS's "APA Study Guide" states that:
"For technical reasons, the denominator in the PLI's definition generally should be an item that does not reflect controlled transactions. Thus, the operating margin and gross margin PLIs (which have sales in the denominator) generally are used for tested parties (often distributors) that sell to unrelated parties, while the markup on costs PLIs (which have total costs or cost of goods sold in the denominator) generally are used for tested parties (often manufacturers) that buy from unrelated parties."
One point that historically has been an area of contention in these transactions when under audit is the argument that different third-party comparable companies should have been used by the taxpayer to determine appropriate profit to the operating company.
The taxpayer's practice of using third-party service providers who do not own significant tangible assets stems from the fact that the operating companies in those cases do not own significant tangible assets, because the significant tangible assets of the consolidated group (the rigs themselves) are owned by the related-party rig owners. That is why the arm's-length profitability of the related-party operating companies is normally benchmarked by observing the returns of technical service providers in the marketplace who likewise do not own significant tangible assets.
In practice, there have been instances in which third-party companies that own significant tangible assets have been used to corroborate the results of applying third-party service provider mark-ups to the operating company costs. However, in those instances so-called "asset intensity" adjustments were applied to the third-party companies to control for the fact that the related-party operating company did not own significant assets, and under economic theory it would earn a different return than companies with significant assets on their balance sheets. Typically, when such asset intensity adjustments were properly applied to these types of third-party companies, the results corroborated the analysis done using the (non-asset-owning) third-party service providers.
Secondary methods for pricing BBCs include using third-party asset owner results to benchmark the profitability of the related-party rig owners, use of a profit split method, and the economic return model.
When using third-party asset owner results to benchmark the profitability of related-party rig owners, practitioners have generally taken two approaches – use of third-party asset leasing companies outside the O&G industry or use of consolidated drilling companies.
Using companies outside the O&G industry may give rise to a potential problem in that their return on assets may not mirror that in the O&G industry, and their performance may not be related to the price of oil. Given the fact that the annual return of the rig owner's assets in the marketplace (namely, the drilling rigs) are closely related to the price of oil, comparability issues may surface that must be addressed when using such an approach.
Likewise, using other third-party consolidated drilling company results to benchmark the profitability of the related-party rig owner is problematic, because each company may have a very different mixture of drilling assets, and the value of the drilling assets may vary dramatically depending on the particular classes of the assets. Thus, the specifications of the rig (for example, drillship versus jack-up) typically drive the day-rate and have a direct impact on revenue and profit potential. As a result, it may be very difficult to justify a particular rig owner's profitability using the results of consolidated third-party drilling companies.
Another method for pricing BBCs is the profit split method. The two applications of the profit split method specified in the US transfer pricing regulations include the comparable profit split method and the residual profit split method. The comparable profit split method, in theory, relies on comparable third-party profit splits between drilling rig BBC participants; however, in practice this kind of data is virtually nonexistent. Therefore, in practice the residual profit split method is more practical, though it still remains a method that traditionally has not been employed.
The residual profit split method uses the "system profit" (the sum of the rig operator's and rig owner's profits), and first allocates some of that profit to "routine contributions." The US transfer pricing regulations define routine contributions as "contributions of the same or a similar kind to those made by uncontrolled taxpayers involved in similar business activities for which it is possible to identify market returns. Routine contributions ordinarily include contributions of tangible property, services and intangibles that are generally owned by uncontrolled taxpayers engaged in similar activities." The amount of system profit that is left after the allocation of income to routine contributions is defined as residual profit. The residual profit "generally should be divided among the controlled taxpayers based upon the relative value of their contributions of intangible property to the relevant business activity that was not accounted for as a routine contribution."
The basis whereby the residual profit should be allocated to the parties (for instance, capitalised cost, fair market value, etcetera) remains a topic of vigorous debate. Moreover, offshore drilling firms typically may not own valuable intangible property on which to base a traditional application of the residual profit split method. However, the IRS in some cases may argue that the operating companies own valuable marketing and know-how intangibles. Because these types of intangibles are not generally reflected on the operating company balance sheet, the IRS's task in quantifying and valuing them appears particularly onerous.
The economic return model is another method that may be used to price BBCs. The model derives BBC payments as a function of a number of factors that impact the cash flow of the asset owner eventually benchmarking the rate of return to the asset owner. One of the benefits of this method is consistency, because it charges all affiliates the same BBC rate for the same vessel. In addition, because the operator bears certain risks under this method, it may earn additional income that satisfies local tax authorities. On the other hand, it may not properly reflect higher lease rates during periods of strong demand.
c) Considerations in selecting transfer pricing method
The primary consideration when selecting a transfer pricing method is the types of data available to the analyst. BBC transactions of drilling rigs between unrelated parties are extremely rare, and the prices may not be publicly available. In addition, because such transactions are rare they may not be made in ordinary circumstances, and therefore may not satisfy the comparability standards of the US transfer pricing regulations. As a result, the comparable uncontrolled price method and the comparable profit split method are generally not applicable.
Financial statements for the rig owners and rig operators will generally be available, but there may be issues with respect to segmentation of those financial statements in relation to the related-party transactions under review. However, the financial statements generally will allow for application of the comparable profits method. Two key issues with respect to application of the comparable profits method are the selection of the tested party (the rig operator or the rig owner) and the selection of comparable third-party companies.
With respect to the question of which related party should be the "tested party," the regulations state,
"…the tested party will be the participant in the controlled transaction whose operating profit attributable to the controlled transactions can be verified using the most reliable data and requiring the fewest and most reliable adjustments, and for which reliable data regarding uncontrolled comparables can be located. Consequently, in most cases the tested party will be the least complex of the controlled taxpayers and will not own valuable intangible property or unique assets that distinguish it from potential uncontrolled comparables."
The rig owners possess an asset that by all accounts is specialised and unique, and it is not generally believed that there are publicly available third-party companies that possess solely comparable assets or assume comparable risks. Therefore, traditionally the rig owner is not selected as the tested party when applying the comparable profits method to BBC transactions.
There is, however, an ample amount of publicly available data on the rates of return earned by third-party technical service providers. While the nature of the technical services rendered by the third parties may not be identical to those rendered by the related party, the level of comparability between third-party service providers and the rig operator is believed to be much greater than the level of comparability between third-party asset owners and the rig owner (due to the unique nature of the drilling asset).
The best transfer pricing method also depends on the intercompany arrangement as structured by the taxpayer. For example, through intercompany BBC agreements, a taxpayer may explicitly shift price risk to the rig owner entity, thereby insulating the rig operator from fluctuations in day rates due to fluctuations in the price of oil. As a result, the rig operator may be relieved from both capital and price risk, and therefore its arm's-length return may not be related to companies operating in the O&G industry. Consequently, selection of the transfer pricing method and its application should appropriately reflect such facts.
The BBC represents one of the most substantial transfer pricing issues facing the offshore drilling industry today and there are several approaches to pricing BBCs in the offshore oil and gas industry. Taxpayers often taken the traditional approach outlined above, which while being accepted by multiple tax jurisdictions, remains under some scrutiny.
All transfer pricing analysis should be based on the facts and circumstances of the particular taxpayer being considered. However, there are a host of non-transfer-pricing considerations that should also be addressed by taxpayers when structuring BBC arrangements, and taxpayers should consult with their legal, international tax, and transfer pricing advisors as tax authorities will likely continue to demonstrate great interest in this issue.
Senior Manager, Transfer Pricing
Deloitte Tax LLP
2200 Ross Ave., Ste. 1600
Firas Zebian is a Ph.D. economist and a senior manager in Deloitte Tax's Dallas, Texas transfer pricing practice. He has more than six years of transfer pricing consulting experience. Firas has managed various engagements for large Fortune 500 clients, overseeing engagements related, but not limited, to global restructuring, global documentation, cost sharing, intangible valuation, headquarter cost allocation, intercompany financing, planning studies and audit defence. He also provided services to clients in Europe, Latin America, and Asia.
Firas has experience in multiple industries (energy, software, food & agribusiness, retail, services, and information technology) and is a regular speaker on transfer pricing and business model optimisation issues at the International Bureau of Fiscal Documentation and Tax Executive Institute, among others.
Senior Manager, Transfer Pricing
Deloitte Tax LLP
1111 Bagby Street, Suite 4500
Linda is a senior manager and Ph.D. economist working for Deloitte Tax's transfer pricing practice located in Houston, Texas. She assists in advising multinational companies in their global and regional operations, intellectual property migration strategies and the establishment, evaluation, and monitoring of their intercompany pricing policies. Linda's clients have included companies operating in a wide variety of industries, such as oil and gas, semiconductor, chemicals and medical device manufacturing. Linda has extensive experience managing large transfer pricing engagements, including US and global documentation and planning studies.
Manager, Transfer Pricing
Deloitte Tax LLP
1111 Bagby Street, Suite 4500
Joe Wood is a manager with Deloitte's global transfer pricing practice in Houston, Texas. He assists clients in the areas of global transfer pricing documentation, business model optimisation, and transfer pricing tax audits. Joe joined Deloitte after serving three years as the senior economist for the IRS transfer pricing practice in Texas. Before that role, he was an Economist in the Houston office of the IRS LB&I Division. Before joining the IRS, Joe held other Big 4 transfer pricing roles.
Joe has extensive experience auditing transfer pricing issues involving profit split methods, IP migrations, cost-sharing arrangements, high-value services, offshore procurement, asset leasing, and other issues related to business restructurings. During his time with the IRS, he worked on large oil and gas and technology sector multinationals in the US, and he successfully argued and resolved cases at the field examination, IRS appeals, and APA programme levels. Joe also completed expert witness training at the IRS, and he understands the strategic relationships between the audit and litigation process.
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