Transfer pricing: Transfer pricing in the oil and gas sector: A primer

To the uninitiated, the enterprise by which companies explore for hydrocarbons, bring them to the surface, and deliver them to our cities seems remarkably simple. While the world is busy consuming about four million barrels of oil every hour – an amount equivalent to the daily production of one "Super Major" exploration and production (E&P) company and the carrying capacity of two oil tankers – most of us are blissfully unaware of the complex systems, processes and tools necessary to fuel our economy. Indeed, the incredible risks associated with these activities were, until recently, not widely understood by those outside the industry.

Events taking place in the US Gulf of Mexico during the spring and summer of 2010 arguably destroyed some of this naiveté forever. On April 20 2010, the Deepwater Horizon, a huge dynamically positioned drilling rig located 49 miles off the Louisiana coast and drilling in 5,000 feet of water to tap hydrocarbon reservoirs 13,000 feet below the sea floor, exploded, resulting in the loss of 11 lives. Efforts to contain the well through engaging the blowout preventer (BOP) using remotely operated underwater vehicles, stuffing the damaged BOP with heavy drilling fluids, and capping the well head with a containment dome, all failed. The deep reservoir, which was pressurised at more than a thousand pounds per square inch, was effectively "killed" months later by the drilling of two relief wells, re-cementing, and the replacement of the 300 tonne BOP.

These painful containment events were captured for the public on television and made visible the dynamic and uncertain world of oil E&P. Commentary around the spill compared E&P activities to exploring outer space, and made the point that the technology and processes necessary to carry this out safely are still being developed. Due to a moratorium on offshore drilling to address these concerns, activities at 33 well sites in the Gulf were suspended.

While offshore activities suffered from the conflagration in the Gulf, US land-based E&P operations were experiencing a blowout of a different and more positive kind. "Unconventional" sources of hydrocarbons – tight gas, coal bed methane, and perhaps most importantly, gas in shale formations – have completely transformed the global energy landscape. These resources, which could not be exploited previously, are now a commercial reality thanks to improvements in drilling and completion techniques such as hydraulic fracturing, horizontal/directional drilling, and real-time visualisation of the drill path.

Due in part to these innovations, the US shale gas industry grew by 45% a year between 2005 and 2010. Indeed, of the 584,670 net new private sector jobs created in the US between 2003 and March 2012, 209,630 have been in the O&G production sector, indicating that 36% of all net new private sector jobs created in the US during the last 10 years have been in the O&G production sector, resulting in 86% increase in employment in this industry. The abundance of natural gas has also invigorated manufacturing industries that depend upon gas as a feedstock (such as petrochemicals). Just a few years ago, the US was expected to be a big importer of liquefied natural gas (LNG) and built an infrastructure to regasify more than 100 billion cubic meters of imported natural gas per years. The US is now estimated to have enough natural gas to supply its domestic needs for over a century and these regasification facilities remain mostly idle. While European and Asian consumers currently pay four to six times more for natural gas than their counterparts in the US and would do well to exploit their own unconventional reservoirs, the confluence of favorable regulations and infrastructure that has made this price differential possible is not as robust in other countries.

As the narrative above emphasises, the O&G sector is a mixture of both unfortunate and happy coincidences, the complexities of which even industry participants struggle to forecast correctly. Additionally, whether on land or sea, the act of finding and producing hydrocarbons is expensive, complex, and generally not well understood. But for all the complications associated with the business end of this industry, the tax issues in the energy sector are even more difficult to navigate. Due to the fact that most multinational O&G companies are forced to stretch their supply chains across far flung places and exchange billions of dollars of commodities, equipment, engineering services and intangible/intellectual property (IP) among their controlled affiliates, transfer pricing risks are one of the largest tax uncertainties faced by these companies.

The O&G supply chain: an overview of the industry and functions of key participants

The accumulation of commercial quantities of O&G in the Earth's surface is actually a rather rare occurrence. Hydrocarbons form deep beneath the Earth's surface when organic materials deposited in ancient sediments slowly transform in response to intense heat and pressure. Over the course of millions of years, these materials "cook" into liquid (crude oil) and gaseous (natural gas) hydrocarbons. The hydrocarbons escape their source rock through porous mineral layers such as faults and fractures and tend to migrate upward because they are lighter in density than other fluids in the rock pores. If there is a path that leads to the surface, the hydrocarbons will emerge above ground in a seep or tar pit. If an impermeable layer of rock blocks the migration, a trap is formed and the hydrocarbons can accumulate in porous rock beneath the trap. Traps are often formed by salt domes, shale, chalk and other formations. The business of drilling for O&G consists of finding and drilling into these reservoirs of porous hydrocarbon-filled rock.

Upstream sector

Finding economically viable sources of hydrocarbons and bringing them to the surface is one of the fundamental activities performed by the companies that operate in the upstream sector of the O&G industry.

Exploration and production

The E&P companies operating in this sector focus on the acquisition, exploration and development of properties for the production of crude oil and natural gas from underground reservoirs. This process generally takes several years to complete. A geologist starts the process of finding hydrocarbons by looking for large structural traps, source and reservoir rocks in a particular geological basin. Seismological techniques are used to investigate subsurface conditions and construct subsurface maps and surveys of the reservoir. Seismic exploration involves four steps: acquisition of data about the geology by recording sound waves as they echo off various boundaries of rock layers; processing the seismic surveys using high powered computers and software algorithms that apply mathematical and geophysical theories about seismic reflections; displaying the processed data in 3D and 4D (with the 4th dimension being time) formats in visualisation rooms; and interpretation of the seismic mapping by geophysicists and geologists.

Some of the greatest improvements in petroleum exploration during the last two decades have involved new seismic acquisition techniques and computer processing of digital seismic data. Since seismic surveys contain huge amounts of data, various advancements are purely the result of increases in computing power. But considerable progress has also been made from the development of advanced algorithms that improve seismic imaging, especially in subsalt formations. Many offshore basins have extensive layers of salt through which traditional seismic methods are ineffective. These new algorithms have allowed E&P companies to identify salt domes and the reservoirs trapped beneath them. Several recent discoveries in the Gulf of Mexico and off the coast of Brazil point to the success of these techniques. The Brazilian find, 150 miles off the coast of Rio de Janeiro, could contain eight billion barrels of oil, buried under four and a half miles of water, sand, rock and salt deposits.

The information gathered through seismic surveys determines where exploratory wells are drilled. Seismic records, however, do not identify the individual sedimentary rock layers and must be supplemented with additional testing. To avoid damaging the reservoir, this normally involves tripping the drill pipe out of the hole and using wireline well logs and drillstem tests, whereby an instrument is lowered down the well to record the properties of the formation, well pressure, the fluids in the well, the geometry of the wellbore, etc.

Modern rotary drilling rigs have a number of complicated parts, each designed for a single purpose, but operating in a mechanical symphony: a derrick that provides the frame to raise and lower equipment into the hole; a hoisting system; a mud-mixing and circulating system including pumps and tanks (drilling mud is used to remove cuttings from the well, to balance pressure in the reservoir and keep the hole from collapsing); a top drive engine to rotate the drill string; the BOP, which prevents pressurised gas and liquids from escaping the well and has hydraulic rams to shut the drill pipe or disengage the rig if control of the well is lost; equipment racks; housing to shelter meters, equipment, and offices/quarters for rig personnel.

While most people think of underground O&G deposits as deep pools of hydrocarbons, O&G reservoirs are typically wider than they are deep. It is therefore difficult to access the whole reservoir by drilling vertically. Starting in the 1990s, the industry began to develop technologies and processes to keep the wellbore in the pay zone of the reservoir. Chief among these were rotary-steerable drilling assemblies that allowed for horizontal or directional drilling.

Directional drilling allows reservoirs to be tapped a long distance from the well site. It includes all forms of drilling where the end point of the well is distant from the well site rather than directly beneath it. Directional drilling techniques have been enhanced by the placement of logging and measurement devices just above the drill bit on measurement-while-drilling and logging-while-drilling tools and systems. These allow the operator to visualise the drill path through the Earth in real time, to make corrections to stay in the pay zone, and avoid obstacles. Horizontal drilling may be three or four times more costly, but the production factors can be as much as 15 to 20 times better than conventional vertical wells.

After the well is drilled and tested, there are two options for the E&P company: the well is either plugged and abandoned as a dry hole or, if commercial amounts of oil and/or gas are found in a test well, the process moves to the completion stage by setting pipe. Completing the well is typically more expensive than drilling a well. During this stage, production casing is screwed together, lowered into the well and cemented to the outside of the wellbore. After the cement job, a wellhead is installed. This is a combination of steel flanges, spools, valves, chokes and manifolds, assembled into what is known as a "Christmas tree," which is designed to provide surface control of the subsurface fluids. Subsea production systems, or "wet trees", are complicated hydraulic and electrical structures installed on the sea floor and connected to floating production, storage, and off-loading vessels (FPSOs), subsea pipelines, or other platforms at the surface.

One or more flow paths are then constructed by shooting holes in the casing and cement and into the reservoir along production zones using a perforating gun. This enables hydrocarbons to travel between the reservoir and the earth's surface. Production tubing is run through the casing and pumps are installed (most oil wells require a pump to lift the liquids to the surface).

Even after the well is successfully completed and starts producing it may not be profitable. Some of the most common reasons are: mechanical failures; the wellbore missed the target zone or was improperly placed within the zone; permeability of the reservoir geology was low; the well failed to intersect fractures; drilling damaged the formation; drilling mud or chemicals leaked into the formation; the well traversed unexpected variations in rock formations causing water coning or sand to invade the wellbore; the presence of flow barriers, such as shale streaks inhibited production; or feasibility studies were poor.

A number of special-purpose logging and measurement tools may be lowered into the cased-hole to evaluate the condition of the well and reservoir. Well interventions can range from a workover to clean-out and repair the well, re-cementing, multi-zonal production, well stimulation, or abandoning the well. Since production rates in all wells decline as the reservoir is depleted by production, well stimulation is a common solution to increase production. An important process in this regard, especially in unconventional reservoirs, is hydraulic fracturing. This process, which was developed in 1948 to replace the (dangerous) use of explosives to stimulate wells, involves pumping large volumes of water, chemicals and sand under high pressure into the reservoir to split the rock and increase permeability. This process, combined with horizontal drilling and other technologies, increases O&G production rates up to 30 times initial rates and has made possible the US shale gas plays discussed above. Enhanced oil recovery techniques, such flooding the well with surfactants (such as detergents) or carbon dioxide, are an important development area for E&P companies as these methods are anticipated to increase production rates in mature wells and in formations with low permeability.

Ultra-deep water discoveries of what appear to be large deposits of O&G have been found recently off the coasts of Angola, Brazil, Sierra Leone, and Nigeria and in the Gulf of Mexico. Accessing these reservoirs will be extremely difficult as the spot where the drill bit hits the seafloor is some 5,000 feet or more below the rig floor and the target reservoir may be another three miles below the seafloor. Indeed, the cost of offshore drilling activities escalate almost exponentially with water depth. Given these costs and the concerns mentioned above about offshore drilling in general, it is not surprising that E&P and oilfield services companies have begun to invest heavily in the development of ultra-deep water drilling techniques, tools, and processes, including remotely operated underwater vehicles, well control/containment devices, rig automation, smart algorithms to address alarm management, training, maintenance procedures/documentation (especially for the BOP stack), and equipment that can withstand the high pressure and high temperatures required for drilling in this environment.

Equipment and oilfield services

What makes the O&G industry unique is not just the difficulty and risks faced by its participants, but also the fact that there are so many companies coming together at the well site to undertake this enterprise. Most of the drilling and completion activities discussed above are not performed by the E&P companies themselves, but by companies that operate in the equipment and oilfield services sector of the O&G industry. Some 85% to 95% of the money that E&P companies spend to develop O&G opportunities goes not to their own engineers, scientists and operating staff, but to service companies and suppliers.

Consider the list of oilfield market segments in Table 1. Hundreds of independent companies operate in each of these segments around the world. These companies manufacture equipment or build it on site, rent, repair and maintain it once in operation, and provide related products to E&P companies. Along with every piece of equipment and tool comes a plethora of services. The largest market segments in terms of global revenue are offshore contract drilling, offshore construction services, pressure pumping services, land contract drilling services, tubular goods (such as drilling pipe), geophysical equipment and services (such as seismic), rig equipment, subsea equipment, wireline logging, and directional drilling services. All in, these segments represented $189 billion worth of equipment and services in 2011. Revenue for the whole oilfield equipment and services market was $275 billion in 2011.

A typical E&P endeavour may have different companies performing each of the activities listed in Table 1. It is difficult to think of a more fragmented industry whereby so many critical processes and activities are outsourced. Moreover, these oilfield services companies also work together with independent oil companies (IOCs) and national oil companies (NOCs) to develop the intellectual property and innovations necessary to respond to evolving demands and are often relied upon to fill engineering gaps faced by the E&P companies. Recently, the whole industry has been focusing on technologies and processes that better integrate the activities of these disparate groups of service providers and to develop knowledge sharing platforms so that information learned on one well can be leveraged.

Midstream sector

The gathering, processing, storage, and transmission of natural gas, and the gathering, storage, and transportation of crude oil are the main operations of the midstream sector. Crude oil and other products are transported internationally in barges or tankers on water, and on land by trucks, and pipelines. Natural gas typically moves via pipeline from the producer to the gatherer or transmission company, and then on to the distributor. These products are typically stored in bulk terminals, refinery tanks, pipeline tanks, underground salt domes, barges, tankers, and inland ship bunkers.

Downstream sector

The downstream sector consists of mainly refining and marketing activities for crude oil, refined products, and natural gas. This includes the refining of crude oil into various products like gasoline, jet fuel, and diesel. Once the oil products are refined, they are sold to wholesale distributors, who sell to retailers and industrial users. Gasoline may also be sold directly by refiners to retail gasoline stations bearing the company's brand name and emblem or independent dealers who own their stations and sell branded gasoline and other products from one or more oil companies. The distributors of natural gas and gas utilities receive their supply from transmission pipelines and deliver it to the public through their own distribution facilities. Their customers include residential, industrial, commercial, and electric utility end-users.

The different segments of the O&G industry are depicted in Diagram 1.

Diagram 1: Oil and gas supply chain

Transfer pricing regulations and guidelines

The US Treasury Regulations section 1.482 (Treas. Reg. § 1.482) generally require that transactions between related parties occur at prices consistent with those between unrelated parties. This is based on the arm's-length principle, which is also adopted in article 9 of the OECD Model Tax Convention. Specifically, Treas. Reg. § 1.482 states that: "A controlled transaction meets the arm's-length standard if the results of the transaction are consistent with the results that would have been realised if uncontrolled taxpayers had engaged in the same transaction under the same circumstances (arm's length result)."

The generally agreed upon practices of the member countries of the OECD for determining transfer prices are addressed in the OECD report Transfer Pricing Guidelines for Multinational Enterprises and Tax Administrations (OECD Guidelines). The OECD Guidelines and Treas. Reg. § 1.482 set out methods for establishing arm's length transfer prices for tangible goods, services, technical assistance, trademarks, or other assets that are transferred or licensed between related or controlled parties. These guidelines are widely accepted globally, with most countries formulating their transfer pricing rules around the guidelines, while others enact specific stringent regulations which are not far off from the purview of the guidelines. In the US, the Treas. Reg. § 1.482 describe a set of methods that practitioners may use to determine whether the prices charged in controlled transactions are consistent with an arm's-length standard. Practitioners may also apply methods that are not specified in the regulations if they are likely to yield a more accurate result than the specified methods. In practice, there is little difference between the transfer pricing methods described in the OECD Guidelines and those in Treas. Reg. § 1.482, other than the fact that latter have specified methods for cost sharing arrangements that address the joint development of intangibles between two or more related parties.

In addition to specific tax regulations addressing the energy sector, many petroleum exporting countries are adopting transfer pricing documentation requirements. These countries include Brazil, Canada, Kazakhstan, Mexico, Nigeria, Norway, Russia, and Venezuela, among others. Interestingly, Russia's recent regulatory changes have been driven by the government's quest for ways to avoid loss of tax revenues and the accompanying capital flight allegedly generated by activity in the O&G industry. In general, there has been a consistent rise in the number of countries with transfer pricing requirements, especially in emerging markets such as China, Russia, Brazil, and India. The number of countries with transfer pricing rules stood at 54 as of 2012 compared with 12 in 1994.

Transfer pricing issues in O&G industry

Transaction flow and transfer pricing in the industry

For transfer pricing practitioners, the energy sector has all the excitement one would want, as multinational participants exchange high volumes of tangible products (oil, gas, chemicals, tools etc.), technical engineering services, loans, and technology on an intercompany basis. Transfer pricing issues cut across each of the streams in the O&G supply chain, especially for the vertically integrated "Super Major" E&P companies. More than 40% of the US cross-border transactions in the O&G sector are actually intercompany transactions between related parties, as explained below.

Of the total O&G products and equipment imported to the US during 2011 of $423 billion, about $175 billion, or 41%, were transactions between related parties. In 2002, only 24% of total O&G imports were related party transactions. In 2011, the amount of US O&G product and equipment exports was about $119 billion, 40% of which were related party transactions; this compares to 27% of the total exports in 2002. These figures suggest a growing importance of intercompany transactions in the O&G industry. The industry as a whole makes up 16% of total US imports and exports. Table 2 shows the 2011 total US transactions and related party transactions for the O&G industry.

The largest intercompany transaction in this industry involves the purchase and sale of crude oil, natural gas and various refined products from upstream producers to the midstream and downstream sector and end users. As can be seen in the table above, multinational energy companies exchanged more than $200 billion worth of hydrocarbons on an intercompany basis in the US during 2011. Typically, these transactions are based upon market price indices that are widely used in the industry, such as Platts, the Oil Price Information Service (OPIS), and the New York Mercantile Exchange (NYMEX). Transactions tied to these benchmarks, whether between related or third parties, are often referred to as being priced "at index" and normally include a "differential" term that adjusts for crude quality (such as heavy/light), location, and other differences relative to the referenced index.

Crude oil and gas are transported using the midstream operations of a third party or an affiliate of an E&P or downstream company. The crude oil sold to a related party refiner serves as the feedstock used to produce refined products. These products are sold to petrochemical manufacturers or retail marketers, which could be either a third party or an affiliate of the refiner. Apart from the sale of crude oil, natural gas and refined products, other tangible transactions include the sale or lease of drilling and production tools and equipment, rigs, offshore construction and production vessels. Consumables, such as sand, mud, water, chemicals and cement must also be used to drill and complete a well. As mentioned previously, a great number of oilfield services companies specialise in the manufacture and delivery of these various products to IOCs and NOCs.

Services are typically embedded in every aspect of the O&G industry and are, therefore, arguably the second largest source of related party transactions after tangible commodity transactions. Intercompany services transactions in this industry are dominated by the provision of engineering and technical services to the upstream sector. These services involve exploration for hydrocarbons using seismic and geological/geochemical techniques, drilling, and testing, evaluation, completing, producing, and stimulating the well. Drilling and production problems require well interventions and workovers – solving mechanical and reservoir issues at the well. Each of these activities has a heavy engineering component and involves specialised tools, equipment, processes and software. Technical services are performed by IOCs, NOCs and oil field services companies, both on a third party and intercompany basis.

To understand the nature of intercompany services in the upstream segment of this industry, it is important to know that the commercial venture of exploring and producing hydrocarbons is typically carried out by multiple unrelated parties, each of whom has a financial interest in the property. The obligations of each party are governed by a number of contractual relationships, such as a joint operating agreement (JOA) and production sharing contract (PSC). A JOA generally governs the relationship between the working interest partners in a joint venture. The operator, typically the E&P company with the largest working interest in a property, has the benefit of being able to manage the project, providing technical resources, decision making and management services to the JOA.

The IOC's host country activities generally involve the use of a controlled foreign corporation (CFC) that is part of a PSC with either an NOC in the respective country, local governments, or other international IOC's that are party to a JOA. Depending upon the jurisdiction, the IOC may own a working interest and operate the project, or it may have working interest with another investor being the operator. In some instances, petroleum exporting countries may restrict the working interest percentages of foreign E&P companies, thus reserving rights to operate the project to local entities or NOC's. Irrespective of the IOC operating the project, it is helpful to think of its CFC as typically having no employees other than its board of directors and officers.

Accordingly, the CFC usually depends upon the parent and affiliates for services associated with the property. If the CFC is the operator of that property, the JOA requires it to provide services for that property. These services relate to exploration, development and production activities, as well as day-to-day management, all of which are provided to the JOA by the parent/affiliates on behalf of the CFC. Managing the costs associated with these activities is of utmost importance to E&P companies. As these expenses represent the company's cash operating costs, they will determine the O&G price that must be received to earn a positive operating cash flow. From a services perspective, an important takeaway regarding the activity under a JOA is that, whether IOC/NOC is the operator or holds a non-operating interest in the property along with a third-party operator, it must provide the same services to either its CFC (as a non-operator) or the JOA (as the operator).

The most important issue for transfer pricing purposes is to note that the IOC/NOC both receives services from third parties and provides services to third parties in the context of its interest in JOAs and that these services are typically proved at cost. The only difference between IOC intercompany and uncontrolled services transactions relates to the fact that the corporate parent, does not have a direct economic interest in the JOA. The approaches to the analysis of services transaction in the context of a joint venture under a JOA is further discussed in the chapter on transfer pricing issues in the shale plays.

Downstream refining and manufacturing operations are also dependent on technical services from related and third parties. Other services transactions include the provision of crude oil trading services by a company to its affiliate, and the provision of management services by the parent entity to its subsidiaries around the globe. Some of the intercompany transactions observed in the O&G industry and their flow are shown in Diagram 2.

Diagram 2: Illustrative types of intercompany transactions and trade flows in the oil and gas industry

In addition to services and tangible product transactions, the performance of a function by a foreign affiliate of an IOC or oilfield services company may be dependent on its access to certain intangibles necessary for the exploration, drilling, production, transportation and marketing of hydrocarbons and refined products. These intangibles cover any intellectual property owned by industry participants, including patents, formulae, processes, designs, know-how, trade marks, brand names, licences, contracts, methods, programs, systems, surveys and technical data, which are licensed or sold to related or third parties. Intangible value may also be embedded in tools and equipment or certain technical services. Other common transactions in the industry are financial transactions such as hedging, intercompany loans, and guarantees.

Common transfer pricing issues in the industry

With so many intercompany transactions taking place in the O&G industry, and the value of these transactions, tax authorities and taxpayers around the globe are increasingly at odds about what is an arm's-length price for related party transactions. The following sections discuss some of the transfer pricing issues that are often encountered by industry participants.

Commodity transactions (oil, gas and refined products)

Historically, E&P companies and other industry participants have sold hydrocarbons to related parties based on well-established indices, such as NYMEX prices, and treated these indices as comparable uncontrolled prices for transfer pricing purposes. This method of pricing intercompany commodity transactions has been treated as sacrosanct by taxpayers and tax advisers alike. This intercompany pricing practice has recently come under scrutiny by taxing authorities (including some US state revenue authorities). The two types of approaches we have seen tax authorities use on commodity transactions are either to ignore the comparable uncontrolled prices and benchmark the distribution return using a broad set of wholesale distributors of all sorts of products, or to reject the differential adjustments made to the indices to account for shipping, location, quality, volume, and other factors the taxpayer uses to increase comparability. Because of the volume of these transactions, such adjustments can create large transfer pricing adjustments.

Take for example an intercompany sale of one million barrels of Venezuelan heavy crude priced on NYMEX settlements of West Texas Intermediate minus a quality differential of $14.50. The intercompany price would be the NYMEX price minus $14.50 per barrel. If a tax authority rejects the differential, the transfer pricing adjustment on this single transaction would total $14.5 million. Similarly, because wholesale hydrocarbon distribution margins are thin and difficult to find comparables for, large transfer pricing adjustments could be seen from application of profit based methods, such as the comparable profits method or transactional net margin method. Identifying stand-alone refineries for benchmarking purposes is equally difficult.

The arm's-length nature of commodity transactions can be justified by demonstrating that the taxpayer has contracts with third parties with similar pricing and terms, that the differentials are market based, and that the index pricing is imbedded in the company's financial systems and therefore less prone to manipulation. The consolidation of commodity trading and hedging activities with the associated de-risking of downstream entities can also reduce the pressure on the intercompany commodity pricing, although tax authorities may view trading operations as routine services in the absence of sufficient substance and capital at risk.

Services

There is a plethora of intercompany services that are provided within the O&G industry. These services range from the provision of engineering and technical services to and on behalf of a related party, to management, administrative, and other operations related services provided by the corporate headquarters of industry participants. Services transactions are analyzed by identifying the total costs, including employee stock options (ESO) and bonuses, associated with the services provided, and determining which activities provide benefit to service recipients. Typically, the costs associated with value added activities are charged to service recipients with some profit element, while all other non-beneficial costs are determined to be either pass-through expenses, or stewardship (or shareholder) related costs. These costs are then allocated to service recipients using an appropriate allocation method. As a result of uncertainty between what is classified as beneficial activity and what is not, tax authorities are increasingly challenging deductions on expenses arising from intercompany services, demanding additional evidence (such as phone/travel receipts, time sheets, task deliverables, etc.) of actual services or increasing the markup on outbound services transactions. The US Internal Revenue Service's (IRS) position on the pricing of engineering and technical services in the O&G industry in particular, appears to be evolving. The types of arrangements under which intercompany services are provided within the O&G industry are not only unique but significant in terms of value. A big E&P company may provide more than $1 billion of intercompany services to affiliates annually. Industry participants often provide the same types of services at cost (or cost plus a small markup) to their related parties and third-party joint venture partners in the context of a JOA or PSC. The pricing to third parties has often been treated as comparable uncontrolled service prices (CUSPs) to determine related party pricing. However, in the US, the use of CUSP in analysing such transactions has been challenged in some cases, as the IRS has relied on the services regulations promulgated under Treas. Reg. § 1.482-9 to compel O&G companies to include both stock option expenses and a profit element in their charges to affiliates, irrespective of whether foreign tax authorities, joint venture partners, or NOCs will accept such charges. At times, the markups required on audit have been very large.

Where the IRS is headed next, however, seems to be an industry specific approach to intercompany services charges that could have significant implications for the O&G sector. It is understood, for instance, that the newly created IRS Large Business and International division is pursuing several industry pilot programmes with a goal to develop policies on the treatment of specific tax and transfer pricing issues, one of which is focused on intercompany services and intangibles in the O&G sector. It is not entirely clear what types of intangibles the IRS is trying to remunerate in this approach. O&G companies clearly employ processes, know how, and technologies to find and produce hydrocarbons. Indeed, the use of new approaches in the discovery and development of oil fields is an industry hallmark and have been exemplified overtime, as geopolitical events and the decline of easily reachable reservoirs are forcing the industry to explore in unconventional places.

The IRS's position in this regard appears to suggest that US based engineers and scientists working for E&P companies produce value at well sites in remote places such as the North Sea and West Africa by combining their expertise with US developed intangibles. The US and OECD transfer pricing regimes accommodates a range of approaches for dealing with the issue. Depending on the characterisation of the transaction, a taxpayer can elect to classify it as a complex engineering service, or a service bundled with intangible property.

Intangible property

The distinction between the provision of a service and the provision of a service bundled with an intangible is somewhat nebulous, especially in the O&G industry. To break this conundrum, it is important to consider whether there is anything proprietary associated with the service, whether the recipient is obligated to employ the results of such services, and if a manual or any other device that "has substantial value independent of the services of any individual" accompanies the services.

Industry participants and transfer pricing professionals are generally familiar with charges between related and unrelated parties for intangibles such as patents, trademarks, technology and know-how. Often, intangible property that is utilized in the related party context (such as patented manufacturing processes) can be licensed for a royalty payment that is benchmarked with either internal or external comparable uncontrolled transactions (CUT) using publically available license agreements. However, while transfer pricing methods for IP transactions are well developed, applying such methods in the upstream O&G sector can create certain complications. Intangibles used by E&P companies have often been developed in tandem with petroleum engineers and geoscientists at major universities, industry consortia and oilfield services firms. These non-proprietary assets are shared freely, in certain cases, with joint venture partners and NOCs in the quest for hydrocarbons, typically on a royalty-free basis. Due to this ambiguity of ownership and the openness by the industry to share knowhow, best practices and technology, allocating a price to this expertise may remain convoluted.

Further complicating intercompany IP valuations is the fact that there are so many different services, process and intangible assets coming together at the well site to produce hydrocarbons. Few of these assets are significant on a standalone basis; it is therefore difficult to value their separate contributions. In other industries, a royalty payment for the value of the IP would be paid in an effort to appropriately compensate the IP owner; in the O&G sector, bifurcating the revenue stream from the sale of the resulting hydrocarbons between the amount resulting from the use of the IP (be it a tool, technique, process or patent) and that associated with more routine contributions is very difficult because of the convolution of activities at the wellhead. In order to avoid these complications, and where the delivery of certain services involve an IP component, some E&P companies and oilfield services companies have chosen to pursue expansive, multiparty cost sharing arrangements (CSA), whereby all legal entities share in the cost of intangible development and are allowed the use of the resulting IP on a royalty-free basis.

Another potential approach to this transaction is to characterise the transfer of intangibles as a sale of the pre-existing IP to future owners of the IP, and characterise future development activities and costs incurred by the parties to the sales agreement as the provision of services. The sale of pre-existing IP could be analysed under Treas. Reg. § 1.482-4, while the provision of services related to IDC could be analysed under Treas. Reg. § 1.482-9. These services/IDCs could be allocated to the parties to the sales agreement at cost plus a profit element depending on the classification of particular activities related to the intangible development activities.

Centralised leasing

Significant leasing activity occurs in the O&G industry between related parties and between market participants. Benchmarking the price of leasing oil rigs, drilling equipment and vessels can be problematic if there are no strong external or internal comparable leasing arrangements (which seldom exist). One common approach to analysing this transaction has been to determine the arm's-length lease rate received by equipment owners as the price that permits the equipment owner to earn cash flow at least equal to its cost of capital after expenses and income taxes over the lifetime of the equipment, where the cash flow has been discounted by comparable equipment owner' cost of capital. Another typical approach is to benchmark the routine return earned on other functions performed by lessees, and allocate the residual profit to the equipment owner. However, these approaches may not overlap and may not be foolproof depending on the type of equipment under lease.

Footnotes

1. Hourly consumption of oil is based on conversion of annual consumption of oil from International Energy Agency, http://omrpublic.iea.org/
   
2. Securities and Exchange Commission Form 10-K of Super Major oil companies.
3. Deep Water, The Gulf Oil Disaster and the Future of Offshore Drilling. Report to the President, January 2011 ("Deep Water Report").
4. Bureau of Labor Statistics data, March 2012, oil and gas extraction and support activities for oil and gas operations.
5. Specifically, the U.S. shale play has been encouraged by an abundance of drilling equipment and open-access pipelines, which have facilitated wildcat exploration in multiple locations, and strong property rights, which bequeath landowners with mineral rights and economic incentives to exploit their holdings. Shale of the Century, The Economist, June 2, 2012.
6. Tax: Uncertain Positions – Will the IRS Refine Reporting Guidance, Financial Executives International, April 2012.
7. Nontechnical Guide to Petroleum Geology, Exploration, Drilling and Production, Norman J. Hyne, PennWell, 2001, and industry publications Upstream (http://www.upstreamonline.com/), Petroleum Economist (http://www.petroleum-economist.com/), Drilling Contractor (http://www.drillingcontractor.org/), the Energy Information Administration (http://www.eia.doe.gov/), Wood McKenzie (http://www.woodmacresearch.com/cgi-bin/wmprod/portal/energy/portalup/index.jsp), and the American Petroleum Institute (http://www.api.org/).
8. The conditions ideal for oil and gas formation are between 180 and 450 degrees Fahrenheit and depths of 7,000 to 25,000 feet, with more gas than oil being produced at higher temperatures and pressure. If temperatures or pressure rise too high, the organic material decomposes to carbon dioxide and water. Oil and Gas Production, Martin Raymond and William Leffler, PennWell, 2006.
9. A geologist is a scientist who studies the earth by examining rocks and interpreting their history. A geophysicist is trained in physics and mathematics to study the subsurface using gravity, magnetic and seismic readings.
10. Brazil's oil boom, The Economist, November 5, 2011.
11. Drilling Smarter: Using directional drilling to reduce oil and gas impacts in the intermountain West, Erik Molvar. http://www.voiceforthewild.org/blm/pubs/DirectionalDrilling1.pdf
12. Critical issues and drilling & completions, Drilling Contractor, January/February 2011 and January/February 2012.
13. Spears & Associates, Inc.
14. Ivetta Gerasimchuk, "Fossil Fuels – At What Cost? Government support for upstream oil and gas activities in Russia", WWF-Russia and the Global Subsidies Initiative of the International Institute for Sustainable Development, pages 11 and 38; Rudiger Ahrend, "Accounting for Russia's Post-Crisis Growth", OECD Economics Department Working Papers, No. 404, OECD Publishing, page 8.
15. For a summary of the transfer pricing regulations for all countries, refer to Deloitte's 2012 Global Transfer Pricing Country Guide. http://www.deloitte.com/tax/strategymatrix
16. The NAICS related party data is sourced from The U.S. Census Bureau: http://sasweb.ssd.census.gov/relatedparty/ Related party trade includes import transactions between parties with various types of relationships including "any person directly or indirectly, owning, controlling or holding power to vote, 6 percent of the outstanding voting stock or shares of any organization," and related-party export transaction is one between a U.S. exporter and a foreign consignee, where either party owns, directly or indirectly, 10 percent or more of the other party.
17. The oil and gas industry in Table 2 is defined as a combination of NAICS code 211 – Oil and Gas Extraction, 324110 – Petroleum Refinery Products, and 333132 – Oil and Gas Field Machinery and Equipment Manufacturing.
18. A JOA in the O&G context is a legal document which irrevocably vests in some person or persons, acting in a representative capacity, the authority to extract and sell O&G for the joint account of two or more partners. Model JOAs are provided by the Association of International Petroleum Negotiators; http://www.aipn.org/modelagreements/. PSCs govern the contractual relationship between a national government or NOC and the E&P companies working the property.
19. Treas. Reg. § 1.482-9.
20. It is important to note that market prices for natural gas are determined regionally, unlike oil prices which are determined in a global context. European gas prices are often tied to the price of oil due to long term contracts with Russian and Norwegian exporters.
21. LMSB Restructuring to Strengthen International Tax Compliance, IRS Says, BNA Daily Tax Report August 5, 2010
22. Treas. Reg. § 1.482-4(b). See also the draft OECD Guidelines Chapter VI, which indicate that an intangible must be capable of being owned or controlled for use in commercial transactions and may be used in connection with a service without an actual transfer of the intangible occurring.
23. Under a CSA, two (or more) related companies agree to share future risks and costs associated with R&D of new technology to be used by each participant in their respective territories, in proportion to reasonable anticipated benefits in future. However, if future R&D is expected to build on current technology developed by one of the companies, the other cost sharing participants must buy-in. Treas. Reg. § 1.482-7(c) calls the payment for such pre-existing technology Platform Contribution Transaction ("PCT"). After buying-in, the cost sharing participant will continue to participate in the development of subsequent technologies based on either the pre-existing technologies or brand new technologies. The intangible development costs ("IDC") associated with these future technology developments is shared by participants in the CSA.

Segun Oladunjoye
		Deloitte 1111 Bagby, Suite 4500 Houston, TX 77002 US Tel: +1 713 982 4798 Email: soladunjoye@deloitte.com Segun Oladunjoye is an economist and a senior consultant in Deloitte's US transfer pricing practice in Houston, Texas. He has about four years of transfer pricing experience, which includes applying economic concepts to the analysis of inbound and outbound transfer of tangible goods, provision of services, license of intangible property, and intercompany lending. In addition, his broad experience within the oil and gas supply chain includes the application of financial modeling techniques to the valuation of intangibles and lease of assets between related parties. Oladunjoye has also assisted Fortune 500 clients in a variety of industries including chemicals, death care, manufacturing, retail, software, real estate, and oil and gas, with their transfer pricing issues. Before joining Deloitte, Oladunjoye taught quantitative methods and econometrics courses at the University of Guelph, Canada. He is published in the Energy Economics journal and referees for various energy journals.

Nadim Rahman
		Deloitte 1111 Bagby Street, Suite 4500 Houston, TX 77002 US Tel: +1 713 982 3963 Email: nrahman@deloitte.com Nadim is a senior manager and an economist in Deloitte Tax's US transfer pricing practice and has seven years of transfer pricing experience working in both the Dallas and Houston markets. During his tenure with Deloitte Tax, he has managed various projects for large Fortune 500 clients, overseeing work related to global documentation, cost sharing, intangible valuation, headquarter cost allocation, intercompany financing, planning studies, competent authority assistance, and audit defence. He has developed relationships with clients in the US, Europe, Asia, and Latin America. Nadim works on a variety of diverse industries and has a focus on energy and oilfield services industries. Nadim has an MSc degree in economics from Texas A&M University, was a Visiting Student in the MBA programme at the Indian Institute of Management, Ahmedabad and has a bachelors of technology degree in mechanical engineering from the Indian Institute of Technology in Mumbai. Nadim is a member of the American Society of Mechanical Engineers and the American Bar Association.

Randy Price
		Deloitte 1111 Bagby Street, Suite 4500 Houston, TX 77002 US Tel: +1 713 982 4893 Email: raprice@deloitte.com Randy Price is the leader of Deloitte Tax's transfer pricing practice for the Houston office. His transfer pricing practice involves client projects spanning the entire energy value chain. Randy's primary area of focus is helping energy related clients address global transfer pricing planning, documentation, and tax controversy matters. In addition to his core energy related experience, he has significant experience with transfer pricing issues involving the cost sharing of intangibles and related buy-in payments for technology focused industries. Before joining Deloitte, Randy spent more than 10 years as an international tax/transfer pricing executive for a Fortune 500 multinational company where he developed, implemented, and ultimately defended multiple transfer pricing transactions from the Internal Revenue Service exam phase through appeals. In addition, he has experience with transfer pricing planning and controversy matters in multiple jurisdictions outside of the US. Given Randy's experiences both within industry and Deloitte Tax, he provides the key practical and technical transfer pricing skills sets that clients' appreciate in today's complex transfer pricing environment.

John Wells
		Deloitte 2200 Ross Avenue, Suite 1600 Dallas, TX 75201 US Tel: +1 214 840 7558 Email: johnwells@deloitte.com John Wells is the mid-America leader of Deloitte's US transfer pricing practice and the US energy sector leader. He is experienced in managing large projects involving quantitative analysis in the areas of transfer pricing and intangible valuation. Although his primary focus has been on the energy sector, Wells has provided services to clients across the industry spectrum, including Fortune 500 companies in chemicals, engineering, manufacturing, retail, software, and telecommunications. Before joining Deloitte, Wells was the lead economist for the global energy and national resources sector of another big four firm, and an economic adviser to the Kuwait government. Wells was also a professor at Auburn University, where he taught PhD-level courses in time-series analysis, macroeconomics, and international finance. He has numerous publications and was a referee for the American Economic Review, Economic Inquiry, and other journals. Wells was awarded a National Science Foundation grant for his work on the effects of political events on financial markets.