TAXATION AND PRICING OF NATURAL GAS: THE DUTCH TRANSITION TO A GAS HUB AND LESSONS FOR AUSTRALIA’S INTEGRATED GAS PROJECTS

摘要

Currently Asia-Pacific region suppliers of LNG (Australia, Malaysia and Papua New Guinea) and their customers in East Asia (China, Japan and Taiwan) negotiate gas prices under the Japanese Crude Cocktail (JCC) oil-indexed long term contracts (Roger and Stern 2014). As the region lacks a transparent LNG pricing benchmark, there is a fundamental reliance by customers on such contracts to guarantee security of supply — and by suppliers — to ensure they get a reasonable return on their gas project investment, including coverage of taxes. Nonetheless there is considerable academic literature that canvasses the establishment of a market hub for gas pricing in the Asia-Pacific (eg. Vivoda 2014, NERA 2016, Nikhalat-Jahromi et al. 2017, Kim 2017, Sung 2017). The discourse on future improvements to the Asia-Pacific LNG export market is dominated by calls from East Asia customers for greater transparency in gas price setting. As Australia is a major exporter of gas, its government is cautious about fostering the development of a gas hub market, as the value of feedstock gas used for liquefaction is a factor in the calculation of the tax base to determine the petroleum rent tax revenue. A rent tax is applied to petroleum (oil and gas) projects in locations under Australian jurisdiction (Petroleum Resource Rent Tax Assessment Act 1987). A rent tax, which is a type of royalty, is a secondary tax that targets above-normal profits or economic rent from a resource. In Australia, multinational companies operate mega-integrated gas projects that extract gas and liquefy the feedstock gas into LNG, which is transported by tanker to export customers. Typically there is an absence of an arms-length sale price for feedstock gas in an integrated project. Thus for gas projects in Australia, corporate taxpayers are required to use the gas transfer price (GTP) methodology detailed in government regulations to determine feedstock gas prices. In essence, the regulations use the Net Back and Cost Plus pricing methods allowed by the OECD (2017), however we argue that in practice, the prescribed use of the methods in combination to derive an average price for the GTP negatively affects the government’s tax base. There is a gap in the literature to consider the perspective of Asia-Pacific exporter countries in the general call for greater transparency in gas prices. In order to close this gap we analyse the successful transition by the Dutch from mechanistic gas pricing to market hub gas pricing for their Groningen gas fields, and possible lessons for Australia’s transfer pricing problems in integrated gas projects.