Primer on liquefied natural gas transfer pricing

Recent developments in the US natural gas market, namely the surge of unconventional (shale) gas development projects, have resulted in an unprecedented market shift as a market once primed for natural gas import now explores exporting significant volumes of natural gas. In light of these developments, many players in the natural gas space have sought opportunities to capitalize on market dynamics and take advantage of the large price differential between the Asian and US natural gas markets. Due to the complexity of the natural gas value chain and number of participants, such export opportunities may present various transfer pricing implications.

In the sections below, we describe the functions provided, risks borne and assets contributed by common participants of the liquefied natural gas (LNG) value chain. This is followed by a brief commentary on the "acting in concert" principle and an overview of common transfer pricing methodologies employed in the natural gas industry. Lastly, we provide some transfer pricing considerations that should be monitored as market participants shift from import facilities to export or bi-directional facilities.

In general, when evaluating complex supply chains from a transfer pricing perspective, it is important to examine the functions performed, risks assumed and assets contributed by each participant to i) properly perform comparability analysis and ii) determine the economically significant contributors to the value chain (as such contributors generally attract a higher return). Specifically, we have outlined some of the common functions of LNG value chain participants below.

E&P functions generally include activities related to the identification, extraction, and production of hydrocarbons. The E&P function is often responsible for obtaining appropriate permitting, undertaking geological/geophysical studies and well testing, constructing the (on/off-shore) assets as well as obtaining appropriate production licenses, among other activities. Depending on the structure of the value chain, the E&P function may also perform entrepreneurial/marketing activities such as entering into long-term supply agreements.

As contributor of the hydrocarbon and production assets to the value chain, the E&P function also undertakes a number or risks, specifically environmental and regulatory risk, risks related to equipment failure and mechanical downtime, risks associated with large fixed costs and hydrocarbon yield risk.

The liquefaction function relates to activities required to cool the hydrocarbons into a liquid state, which can either occur onshore, at a liquefaction facility, or off-shore on a floating LNG (FLNG) vessel. Before compression and cooling, the facility also processes the natural gas to remove impurities and other natural gas liquids. Capital required for a liquefaction facility or vessel is substantial and thus, similar to E&P, the liquefaction function is burdened by risks that include equipment and mechanical malfunctions/downtime as well as those risks associated with large fixed costs.

The shipping/storage function relates to activities that include pre-liquefaction gathering activities and pipeline transportation of the natural gas as well as the transportation of LNG aboard an LNG tanker (post-liquefaction) and or natural gas pipeline. Capital required for a liquefaction facility or vessel is substantial and thus, similar to an E&P and a liquefaction facility, the shipping/storage function is burdened by risks that include equipment and mechanical malfunctions/downtime as well as those risks associated with large fixed costs.

After the LNG has arrived at its destination and been off-loaded from the vessel and stored, the LNG is re-gasified. Capital required for a regasification facility is substantial and thus, this function is burdened by risks that include equipment and mechanical malfunctions/downtime as well as those risks associated with large fixed costs.

The marketing/trading function is responsible for selling the LNG to the end market through the identification of long term sales contract opportunities as well as opportunities to sell natural gas in spot contracts and futures/forward contracts. This function may also participate in portfolio or cargo hedging and is typically responsible for administrative activities related to the long term sales contracts as well as scheduling/logistics when required. The marketing/trading function contributes assets in the form of a working capital and margin account as well as portfolio capability.

As a marketer/trader, risks are borne such as losses from poorly executed arbitrage and hedge trades, speculative trading losses, and/or misaligned contractual clauses (for example, force majeure).

The marketing/trading function typically is the most scrutinised along the value chain as it has the ability to function as a routine service provider (for example, engaging in execution-only trading, general risk management and middle/back office activities) or in an entrepreneurial role should it engage in more complex trading/hedging strategies, actively manages and places its capital at risk. In a similar manner, determining the segment where the marketing/trading function lies within the LNG value chain is difficult due to its dependency on the value chain's specific organisational/operating structure as well as functions performed/risks borne. For purposes of this article, we have noted the function's participation in the midstream segment of the value chain, however, it is possible the function can be present in each segment of the value stream (upstream, midstream or downstream).

Transmission activities include the transportation of natural gas (after it is regasified) to end consumers ( industrial or retail) through a pipeline distribution network. Capital required for a transmission network is substantial and thus, the transmission function is burdened by risks that include equipment and mechanical malfunctions/downtime as well as those risks associated with large fixed costs.

Compared to the more established oil & gas (O&G) industry, the LNG industry is evolving. Thus, newer technologies such as Floating LNG (FLNG) are unproven and therefore impose a risk factor that may require adjustment when computing the required return.

Natural resource projects are often governed by government policy, which has the ability to impact the profitability of the project. This risk is especially relevant for a number of planned export facilities in the US LNG market awaiting final approval. Although these projects have secured long-term supply commitments, the ultimate deployment and economic impact of the project remains obscure until officially sanctioned by the relevant governing bodies.

Further, natural gas resources in geographies with more political instability, are more susceptible to sabotage and may require additional resources dedicated to security.

Traditional methods for attempting to capture country risks are well understood in finance academia, practice and theory. In contrast to many types of country risks, geopolitical risk is difficult to measure as it may result in a binary effect, where the risk matures and the company faces the possibility of being unable to supply hydrocarbons due to complete political unrest or instability.

The functional and risk analysis forms the basis for the selection and application of transfer pricing method(s) when determining an arm's-length price for dealings between related parties.

Due to the sheer volume of investment required to construct and operate the different components along the LNG value chain, it is common that participants embrace similar ownership structures. While investors in the LNG value chain may be unrelated, it is important to consider the transfer pricing regulations promulgated under US Treas. Reg. Sec. 1.482 (§482 Regulations) which apply to transactions that occur between "controlled" parties or a "controlled" group, to determine if a transfer pricing issue exists.

Transfer pricing issues hinge on the facts and circumstances relating to the relationships between the parties and the control of the LNG value chain. The §482 Regulations, however, construe the definition of control broadly and rather subjectively; as per the §482 Regulations, "controlled" is defined as:

"Any kind of control, direct or indirect, whether legally enforceable or not, and however exercisable or exercised, including control resulting from the actions of two or more taxpayers acting in concert or with a common goal or purpose. It is the reality of the control that is decisive, not its form or the mode of its exercise. A presumption of control arises if income or deductions have been arbitrarily shifted."

Thus, while the terms governing the overall LNG value chain might be extensively negotiated between the parties in an arm's-length manner, they may be considered controlled parties for purposes of the §482 Regulations. In our experience, US-based joint venture partners in this industry often decide to apply the §482 Regulations to their transactions to proactively address the treatment of said transactions.

It is important to note that LNG value chain economics and strategies are very dynamic. However, based on our collective O&G industry experience, we have seen the following transfer pricing models generally applied to the operations present in the LNG value chain:

The comparable uncontrolled price (CUP) methodology is commonly used within the LNG industry using pricing from quotation media that is widely and routinely used by uncontrolled buyers and sellers in the commodities markets worldwide to negotiate prices.

Pricing from the following quotation media is often used in negotiations:

NBP prices best represent the European market price for natural gas and are considered close to end users. Belgium's Zeebrugge and the Netherland's Title Transfer Facility (TTF) gas hubs are closely linked to movements in the NBP, as are global pricing movements.

The NBP is also the pricing point for the Intercontinental Exchange (ICE) natural gas futures contract. ICE is a leading operator of regulated futures exchanges and during 2009 over 2.5 million natural gas futures trades were made through ICE.

Though the index is commonly used by traders for financial hedging purposes, physical trading contracts are for delivery of natural gas in the UK. Traders exchange a variety of contracts, including day ahead contracts and monthly futures contracts. When traders reach a consensus regarding a future commodity price, pricing data is created that may be used by other market participants to price their own (physical) purchases and sales of commodities.

Thus, the price quotations generated by the NBP represent the collective current view of the marketplace (i.e. the indirect evidence) of where prices will be set.

Overall, application of the CUP methodology often has many advantages, including its wide acceptance and common application in OECD member countries as well as its ease of implementation. Specifically, such an approach is directly addressed in the §482 Regulations (§1.482-3(b)(5)) as well as proposed in the recently released OECD Discussion Draft on the Transfer Pricing Aspects of Cross-Border Commodity Transactions (proposed for insertion after paragraph 2.16).

However, it should be noted that application of the CUP methodology to LNG transactions has some limitations as it is likely that adjustments may need to be made for differences in terms and conditions (for example, duration, contract date, shipping terms, destination, etcetera).

The residual profit split methodology determines the remuneration due to the entrepreneurs by first determining appropriate returns for each of the members of the LNG value chain. Routine LNG value chain activities (such as transport, logistics, trading) are given benchmark returns for their activities based on the financial data of public companies that engage in similar routine activities. Thus, the routine entities are remunerated according to their limited risks and functions.

The residual profits (or losses) are then split between the entrepreneurs within the system based on share of relative capital or some other appropriate measure.

Profit split methodologies are accepted by OECD member countries and in fact often the outcome of bilateral negotiations between tax authorities (for example, advance pricing agreements) and are emphasised in recent OECD guidance. Taxpayers have implemented this methodology to compensate different members of their supply chain in the natural gas value chain. However, the split of residual profits can be controversial and may cause dispute amongst participating nations' tax regimes or may result in a case of double taxation. This may also prove a more difficult method to administer in cases where a fixed split is levied by a specific jurisdiction (for example, Australia) and would need further consideration.

Another pricing model used within the industry is the net-back pricing model, which employs a number of US/OECD specified methods at the same time in order to determine intercompany pricing for each function of the value chain.

Under the net-back pricing method, a net-back price (ultimate sales price used for the natural gas entrepreneur(s)) to be used between controlled taxpayers is determined by identifying the prevailing gas prices in the market destination (such asEurope, Asia, or other location) and deducting costs and profits related to the different routine natural gas supply chain activities (liquefaction, transport, regasification, logistics, trading, etcetera). Application of this methodology involves the following steps:

• Identification of natural gas price at market destination – The first step (final sales price) is determined through the identification of either i) direct evidence of a CUP (for example, contract sales price with or between an uncontrolled taxpayer(s)) or ii) indirect evidence of a comparable uncontrolled price derived from data from public exchanges or quotation media.

• Remuneration for routine natural gas value chain contributions – The second step allocates operating income to each controlled party to the controlled transactions within the value chain to provide a market return for routine contributions. Routine contributions are 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 intangible property that are generally owned by uncontrolled taxpayers engaged in similar activities. Market returns for the routine contributions should be determined by reference to the returns achieved by uncontrolled taxpayers engaged in similar activities and may be remunerated in the form of a return on costs, return on assets or other reasonable measure. Typically this analysis is performed through the application of the Comparable Profits Method/Transactional Net Margin Method (CPM/TNMM).

• Allocation of residual profit for non-routine contributions to natural gas value chain entrepreneur(s) – A non-routine contribution is a contribution that is not accounted for as a routine contribution. Thus, in cases where such non-routine contributions are present, there normally will be an unallocated residual profit after making the remuneration for routine functions within the natural gas value chain. The residual profit should be allocated to or divided among the principal company/entrepreneur(s) based upon the relative value of their non-routine contributions to the value chain. This can be demonstrated through evidence of the entrepreneur(s) undertaking key decisions, providing intellectual property or bearing risks commensurate with the returns.

Local tax authorities are likely to respect the structure if the markups for each function are consistent with the arm's-length principle and the principal company/entrepreneur has proper substance. Further, the net-back pricing methodology promotes transparency as all intercompany/related party pricing is a net-back off of a market driven price.

In light of the North American renaissance in the production of natural gas from US shale resources, investors have seen first-hand how the natural gas market dynamics can change rapidly (and significantly) in terms of supply/demand, price volatility and economic winners and losers. A US LNG import and regasification industry that had recently invested billions of dollars has been forced into a paradigm shift within just a few years as many market participants have begun exploring opportunities to retrofit an existing import facility (brownfield) to accommodate exports.

Brownfield development projects provide a number of advantages over their greenfield development counterparts. Many brownfield projects already have a site selected and received necessary environmental and regulatory approvals (for example, maritime transport permits, Department of Energy (DOE) and Federal Energy Regulatory Commission (FERC) approvals), which reduces schedule risk as both the regulatory approval process and time to completion can be accelerated. Further, existing brownfield facilities provide some element of cost savings as more than 50% of the assets used for the import facility can be used in the liquefaction process (for example, storage tanks, pipeline transportation, etcetera) and allow for bi-directional optionality should market dynamics change.

While the advantages of a brownfield development appear clear on a macro-level, participants in such developments should remain cognizant of transfer pricing issues that may be present. In cases where changes in ownership structure are made (for example, an import partner is not interested in the export opportunity and would like to divest import interest) or operating rights are transferred between legal entities, a transfer pricing issue may exist in the valuation of the ownership interest and/or transfer of rights. This is likely to result in a complex economic analysis with considerations such as the present value of "unlocking" the export opportunity, costs of unwinding existing tolling arrangements, value of existing FERC and DOE permits and the value of progress in the FERC and DOE approvals queue (schedule risk). Such issues should be monitored as the taxation of US export structures is likely to garner more scrutiny from the IRS as more projects reach final investment decision and come on-line.

Samuel Fletcher Senior Manager, Transfer Pricing Deloitte Tax LLP 1111 Bagby Street, Suite 4500 Houston, TX 77002 Tel: +1 713 982 3152safletcher@deloitte.com Sam is a manager in Deloitte Tax's Houston, Texas transfer pricing practice. He has over 8 years of experience in transfer pricing, specialising in the oil and gas industry, both in Houston and Calgary, Alberta. Sam has been actively involved in a variety of outbound and inbound projects providing services to large multinational clients. His recent engagements within the oil and gas industry include tax and transfer pricing value chain planning related to the export and marketing of natural gas from North America into Asia, transfer pricing planning analysis to determine long-term pricing of LNG cargo transactions, and transfer pricing assistance and successful IRS defense for a marketing and distribution company of crude oil products. Sam has also consulted on cross-border supply chain transfer pricing for clients in the recreational vehicle and software industries.

Randy G Price Director, Transfer Pricing Deloitte Tax LLP 1111 Bagby Street, Suite 4500 Houston, TX 77002 Tel: +1 713 982 4893raprice@deloitte.com Randy Price is the leader of Deloitte Tax's transfer pricing practice in the Houston, Texas office. His transfer pricing experience includes client engagements spanning the entire energy value chain. Randy's primary area of focus is assisting energy-related clients in the management of 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 IRS 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 the industry and at Deloitte Tax, he provides the practical and technical transfer pricing skill set that clients desire in today's complex transfer pricing environment.

Vitaliy Voytovych Director, Transfer Pricing Deloitte Tax LLP 1111 Bagby Street, Suite 4500 Houston, TX 77002 Tel: +1 713 982 2910vvoytovych@deloitte.com Vitaliy is a director in Deloitte Tax's Houston, Texas transfer pricing practice. He has more than 11 years of experience in transfer pricing and economic analysis. Before his career in transfer pricing, Vitaliy was an Economist with a private equity firm, and also worked in the IT consulting industry. Vitaliy specialises in the oil and gas industry (oilfield services and equipment, exploration and production, drilling, marketing, LNG) but has considerable experience in a number of other industries as well, including engineering services, semiconductors, and chemicals. He has extensive experience managing large transfer pricing engagements, including US and global documentation and planning studies, advance pricing agreement (APA) negotiations, and audit defence work.