The Eastern Australian gas market
Charting a pathway for the conundrum of Eastern Australian gas
Historically high wholesale eastern Australia gas prices, a predicted ‘shortfall’ in gas supplies from 2018-19, and a concern that the Australian government is not receiving an ‘equitable’ return for the gas extracted have, collectively, triggered unprecedented attention about the state of the Eastern Australian gas market in 2017.
The principal reasons for the recent and substantial price increases in Eastern Australia include: (1) Expiry of relatively cheap long term gas contracts at a time when new production costs were rising rapidly; (2) Linkage of the Eastern Australian market to internationally traded gas prices with the advent of gas exports in 2015; (3) Supply restrictions on the development of both conventional and unconventional gas in some states since 2010; (4) Slower than expected ‘ramp up’ of gas supply from the gas fields developed for gas exports that has necessitated the purchase of gas that would otherwise have been available to meet domestic demand; (5) market power by gas pipelines owners or operators; and (6) Lack of market liquidity that allows small gas volumes to set wholesale prices, without transparently representing market fundamentals.
In terms of recent price increases, the export of gas from the three LNG plants at Curtis Island has resulted in: (1) a netback price (the export gas price in a destination market less the costs of liquefaction, transportation, and insurance) that now provides a ‘floor’ or price support below which wholesale gas prices cannot be expected to fall. The current netback price substantially exceeds previous long-term wholesale gas contracts (some of which dated back decades); and (2) the purchase of substantial quantities of gas that would otherwise (in the absence of LNG exports) have been available to supply the domestic Eastern Australian gas market, thus potentially creating major market disturbances, and price volatility. Eastern Australian wholesale gas pricing is complicated by the fact that gas exporters have signed long-term (20-30 year) supply contracts with gas importers in the Asia and Pacific gas market. These contracts include a ‘take or pay’ clause that requires the buyers to pay for the gas they have contracted for even if they choose not to take delivery of the gas. Such contracts reduce the market risks for LNG exporters and were instrumental in encouraging them to make the more than USD 60 billion investment in gas export infrastructure at Curtis Island. Along with a ‘take or pay’ clause are ‘point to point’ clauses in the long-term contracts that oblige the gas exporters to supply the gas to buyers from a specific location (Eastern Australia) and to deliver it to the specified destination.
Purchases of gas for export in Eastern Australia, other than from partner’s own production, occurs at only one of the LNG gas export plants at Curtis Island. These gas purchases currently represent about 20% of total Eastern Australian annual gas demand and began with the purchase of 750 PJ of gas over a 15 year period in 2010 from the Cooper Basin. Such purchases have subsequently increased and have further reduced domestic gas supplies that otherwise would have been available in the absence of gas exports.
Another contributing factor to higher domestic gas prices is that much of the gas produced in South Australia, and all the gas produced in Victoria, is extracted using conventional methods of extraction and in gas basins that were first developed decades ago. In general, these older and conventional sources of supply have a lower marginal cost of extraction than the newer gas developments in the Surat and Bowen Basin of Queensland where gas is extracted unconventionally from coal seams, and is commonly known as coal-seam gas (CSG).
Domestic wholesale gas spot prices started to rise with the commencement of gas exports from Cutis Island in the last quarter of 2015, and have exceeded $A8/GJ since July 2016. In early 2017 the ex- Brisbane wholesale gas spot prices exceeded $12/GJ. While domestic gas spot prices are highly variable, over the past five years gas prices have more than doubled, on average, and from trough to peak spot prices have quadrupled from their previous levels. In addition to concerns about high gas prices the Australian Energy market Operator (AEMO) projected, in March 2017, a shortfall in gas within two years. The gas shortfall could be either in reduced electricity generation of up to 363 GWh (less than 1% of electricity generation in the National Electricity market) or shortfalls in gas supply to residential and commercial users of up to 54 PJ per annum between 2019 and 2021 (less than 10% of Eastern Australian domestic gas consumption)
A mix of approaches in terms of market transparency and competitiveness, support for additional gas infrastructure, investments to support energy adequacy in the National Electricity Market, and reform of gas delivery networks offer long-term pathways to respond to the ‘ups and downs’ of gas markets.
Australian domestic gas prices are, and will continue to be, more variable than they have been in the past. This will generate both ‘highs and lows’ for future domestic gas prices. Rather than restricting the flexibility of gas markets, policy makers should continue to improve gas market liquidity, to support price discovery, to review third party access to gas pipelines, and also promote approaches for large domestic gas users to hedge against changes in gas prices.
Policy alternatives, beyond the gas market, include improved incentives for load shedding from large electricity users in the National Electricity Market and even households with demand response approaches and also incentives to encourage additional energy storage to make up for any possible shortfalls in gas-powered generation (noting that the two are not completely interchangeable).
Quentin and Ian are at The Australian National University, Canberra, Australia. Xunpeng is at the University of Technology, Sydney, Australia.