THE LAST 18 months has seen widespread publicity around tax compliance and the impact of tax planning by multinationals which leads to the erosion of source country tax bases – otherwise known as Base Erosion and Profit Shifting or BEPS.
The response from the OECD, revenue authorities and the media initially seemed to focus on companies in the digital economy, however the Australian Taxation Office has made it abundantly clear that BEPS equally applies to the energy and resource industries.
The ATO will be focusing on potential BEPS strategies they believe are employed by multinationals operating in these sectors.
As far as the Australian oil and gas industry is concerned, while many projects have entered into long-term sale and purchase agreements (SPAs), not all production has been committed to customers.
SPAs were historically entered into with related and unrelated party buyers when BEPS was not even a consideration and under Australia’s old transfer pricing regime.
An increased global focus on transfer pricing, and the introduction of much broader Australian transfer pricing provisions means that the oil and gas sector is now operating in a very different tax compliance environment.
Australia has also introduced new thin capitalisation legislation which will dramatically affect the ability of Australian borrowers to deduct interest on major capital loans.
Combined, these changes (and associated penalty provisions), could have major financial implications for taxpayers if not appropriately managed upfront.
The arm’s length debt test
The thin capitalisation rule changes will impact the funding of oil and gas projects in Australia.
The reduction of the safe harbour debt-equity ratio could not only significantly increase the tax cost of existing projects, but also materially impact the viability of future projects in Australia.
The rules also extend beyond just related party or inter-company debt. As such, even if a third party lender has project financed a major capital project like an oil and gas venture, a portion of interest deductions claimed could be denied which could be a significant impost on ongoing project feasibility.
The arm’s length debt test is currently one avenue open to taxpayers seeking to justify a gearing level in excess of the safe harbour level of debt.
Given the asset-intensive nature of oil and gas projects and the regular use of long term SPAs to secure future income, many Australian subsidiaries of multinational oil and gas producers might be able to justify arm’s length debt-equity ratios that exceed the new 1.5:1 safe harbour.
However, in practice, the factual assumptions prescribed for the application of the arm’s length debt test are at odds with commercial project finance practices in the industry (in particular the requirement for sponsor guarantees to be disregarded).
LNG pricing trends and key considerations
Historically LNG has been sold through long-term contracts, with limited flexibility in volume and price. LNG trade patterns have evolved significantly, adding to increased sales of multiple cargoes on the spot market, brokered trades and speculative trading positions.
Asia Pacific buyers are keen to secure supply for local markets while Australian producers, particularly subsidiaries of foreign headquartered groups, are under extreme pressure to sell at very competitive prices.
This tension is placing a sharper focus on LNG pricing trends. Buyers are reluctant to enter into long term contracts without 3-5 year price reopeners, in addition to pricing caps and collars.
This reluctance is partly attributed to the growth of the US shale gas industry and an expectation of large export volumes that may drive prices lower than current Asia Pacific prices.
Continued pricing pressures are causing a shift away from ‘traditional’ Japan Crude Cocktail (JCC) index pricing to the Platts LNG benchmark price assessment for spot physical cargoes delivered ex-ship into Japan and South Korea (the Japan Korea Marker or JKM), and even blended pricing (based on an average of different price indices).
However, while LNG pooling/trading may make commercial sense for multinational groups seeking to achieve economies of scale, revenue authorities are keen to ensure that entities in their jurisdiction are achieving arm’s length returns (and returning sufficient profits), relative to prices ultimately charged by trading entities to end-customers.
In a related party LNG SPA context, the gradient or discount factor applied to JCC prices is critical. This should be based on the terms and conditions of the SPA and in particular, the seller / buyers’ risk profiles.
Substantiating arm’s length terms and conditions operating between related parties in a multinational group context will be critical under Australia’s new transfer pricing rules, and to mitigate the risk of reconstruction by the ATO.
Multinationals that have invested, or are looking to invest, in Australian oil and gas projects must consider these issues to ensure projects remain viable and attractive.
The desire to invest in resource rich Australia, particularly with the LNG industry outlook cannot be denied, but commercial and business objectives must be balanced with tax risk management / outcomes when deciding to invest.
Jacques van Rhyn is a Deloitte Tax partner and leader of the national Transfer Pricing Team.
Janelle Sadri is a Deloitte Tax director and transfer pricing specialist. Both are based in Perth.