The East Coast Gas Market is finely balanced with current conventional and coalbed methane resources stretched to both supply LNG export markets and meet domestic demand. While this situation has developed into a political issue for federal and state governments, exploration companies have been identifying and investigating the potential of Palaeozoic shale gas in the Northern Territory of Australia. It is still early days, but with the advent of the Northern Gas Pipeline linking eastern states with the Northern Territory, any gas reserves commercialised from the Palaeozoic shales could contribute to the future supply of the East Coast Gas Market.
The Australian Gas Market
There are three main domestic gas markets in Australia: the East Coast Gas Market (ECGM) — supplied from Bass Strait and Cooper Basin fields, the West Coast Gas Market (WCGM)— supplied from North West Shelf fields, and the Northern Territory Gas Market (NTGM)— supplied from Amadeus Basin fields.
The ECGM includes the states of New South Wales, South Australia, Victoria, Tasmania, and Queensland, and is largely isolated from the WCGM and NTGM. In 2015, the Australian Competition and Consumer Commission (ACCC) documented that the available gas productivity would be enough to supply the ECGM demand forecast for 2018 (subject to the timely development of reserves and demand changes). Since then, the ACCC has released an updated Interim Report revising its outlook for 2018, and instead forecasts a shortage of between 55-108 petajoules (PJ) of gas.
This shortage has led to domestic gas users facing high prices (ranging between US$10-16 per gigajoule in H1 2017) and increased uncertainty, as suppliers are becoming less willing to enter into long-term contracts. Many industries (including chemical and alumina production) have been affected, and some have even started deferring contract negotiations in the hope that better conditions return.
The Australian Energy Market Operator has estimated that the total domestic demand forecast for 2018 is between 1,956 and 2,009 PJ. The ACCC has estimated that more than 60% of this is attributable to exports from three LNG projects in Queensland, which are: the Australia Pacific LNG project (capacity of 9 million tonnes of LNG per year (MMt/y)), the Queensland Curtis LNG project (total capacity of 8.5 MMt/y) and the Gladstone LNG project (full capacity of 7.8 MMt/y).
With the LNG projects able to export a significant amount of gas produced from a large portion of the available 2P reserves (approximately 60%— mostly coalbed methane), the federal government recognised the need to ensure security of supply to domestic users. To address this, on 1 July 2017 the government implemented the Australian Domestic Gas Security Mechanism (ADGSM), which allows export controls to be placed on the industry depending on the domestic market forecast. If a gas shortfall is predicted, a limit preventing LNG exporters drawing too much gas from the domestic market is invoked. Gas producers have also showed alignment with the federal government by guaranteeing that they would meet forecast domestic demand for 2018 and for years beyond. However, despite these assurances, it is believed no formal agreements have been signed that cement this guarantee.
In addition to the large volume of gas consumed by the LNG projects, the ACCC has recognised two issues limiting the supply side of the balance. The first is the decline in production. The Gippsland Basin currently produces the highest volume of gas, equating to 330 PJ, however this is expected to fall to 244 PJ in 2018, as traditional sources continue to be depleted and final investment decisions are deferred, for example as in Shell’s Arrow gas project.
The second issue is legislative. To date four states: New South Wales, Northern Territory, Tasmania, and Victoria have introduced moratoriums and bans on hydraulic fracture stimulation. These bans have prohibited companies exploring for and developing unconventional resources, which could potentially have a large, positive impact on the supply side of the balance. Through a change of government, the Northern Territory is the most recent state to introduce the restricting regulations.
Northern Territory Palaeozoic Shales
There are seven basins and major sub-basins in the Northern Territory. The Amadeus, Beetaloo, and McArthur basins have historically had the highest level of exploration activity. However, since 2015 only 11 wells have been drilled (all in the Beetaloo, and Georgina basins), by Santos, Origin Energy, and Pangaea. Exploration results from these wells have been mixed, however Origin’s 2015-2016 four-well campaign in the Beetaloo Basin has emerged as one of the most positive.
Figure 1: The basins of Northern Territory, Australia
During the campaign, Origin drilled three wells (Amungee Northwest 1, Kalala South 1 and Beetaloo West 1) that have supported the presence of a laterally continuous, organic-rich source rock of Proterozoic age called the Velkerri Formation. Further analysis has indicated that the middle section (the B Shale) of this formation has excellent source-rock quality, with gas-filled porosity in the range of 3-5%, and geomechanical properties conducive for hydraulic fracture stimulation.
Later in 2016, the Amungee Northwest 1H well was spudded to begin a multistage fracture stimulation test, targeting the B Shale over a 1,000m horizontal section. The average production rate during the 57-day extended test was 1.1 million cubic feet of gas per day (MMcfg/d). Following this, Origin made a preliminary estimate of petroleum-in-place for the Velkerri B Shale Gas Pool, estimating that its acreage potentially held a gross original gas in-place volume of 496 trillion cubic feet of gas (Tcfg) and technically recoverable resources of 85 Tcfg (representing a 16% recovery/utilisation factor).
Figure 2: Origin Energy’s Beetaloo acreage with 2015-2016 well campaign
Potential Economic Impact
Further work in Origin’s campaign has stalled following a moratorium on fracking introduced on 14 September 2016 by the newly elected Labour party. Simultaneous to the moratorium, the party also commissioned a Scientific Inquiry into Hydraulic Fracturing in the Northern Territory. As part of this ongoing investigation, Origin illustrated that a large-scale project could potentially provide 400-500 terajoules of gas per day to the ECGM, based on a 400-500 well project spanning 20 years.
Further analysis in this example suggests that this could represent a life-cycle capital cost of greater than A$5.5 billion (~US$4.3 billion), based on an assumption of an average well cost of A$12 million (~US$9.4 million) and plant costs of A$5 million (~US$3.9 million) per annual PJ of capacity. Further to the additional long-term gas supply, the federal government and Northern Land Council would also benefit from revenues raised by royalties levied on production (which could be up to 12% and 1% respectively), and taxes including the Petroleum Resources Rent Tax, which is set at a rate of 40%, and the Corporation Tax, which ranges between 28.5% and 30%.
Origin’s exploration campaign is still in its infancy but has highlighted the possibility of significant unconventional potential in the Beetaloo Basin and perhaps beyond. This is further mirrored by other exploration companies and the US Energy Information Administration, which have suggested that the Velkerri shales may extend into the McArthur Basin, and that the technically recoverable shale resources in Australia could potentially be >400 Tcfg.
A resource this large is difficult to overlook, and with the Northern Gas Pipeline (scheduled for completion in late 2018) providing a possible transport route to the ECGM, it seems unlikely that these resources will remain undeveloped indefinitely. However, with the moratoriums and bans on fracking currently in place, and the long lead time from exploration to production, it seems remote that any progress made will remedy the forecasted gas shortage in 2018. The federal government has recognised that this legislation is exacerbating the current ECGM situation and is considering imposing penalties on states (through the redistribution of Goods & Services Tax receipts) that do not favour approving development plans based on an individual project basis.
Additionally, the federal government is also reviewing royalty options for landowners to incentivise exploration. A lifting of the moratoriums and bans may also help to boost the declining gas supply by increasing the number of final investment decisions taken, however this is also a function of the oil price, which is currently stunting the economic viability of some projects. To fully re-balance the market, the government also needs to address issues on the demand side. To achieve this, it may impose export limits on the three LNG projects, however this has been deemed as a temporary measure.
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