Australia has built more liquefied natural gas (LNG) capacity in Queensland than there is gas to supply it. That’s not news. But it is a problem.
The GLNG consortium, led by Santos, has the biggest issue in finding enough gas to meet its international contracts, but all the producers have some worries somewhere down the track.
Secondly, the Federal Government announcement on Thursday that it will intervene, if necessary, to guarantee local supply will probably help to ensure the physical security of the East Coast gas Market, but it doesn’t seem as if it will have an impact on the gas price.
Thirdly, no matter how you look at it, the case for building new gas fired generation in the face of a physically tight market is going to be difficult to make.
Fourthly, many details of the new Government policy remain uncertain, making it difficult to predict outcomes with confidence. After initially seeming relaxed on the opening, the Santos share price has moved down 6 per cent at the time of writing, so that seems to suggest investors have some concerns. Santos owns 30 per cent of GLNG.
Federal Govt. announces “Australian Domestic Gas Security Mechanism”
The press release states:
“If an exporter is not a net contributor to the domestic market, that is, they draw more from the market than they put in, they will be required to outline how they will fill the shortfall of domestic gas as part of their overall production and exports…… LNG exporters who are drawing from the domestic market will be ordered to limit exports to ensure local supply”
This announcement is sufficiently vague it’s hard to measure its impact. We don’t know what its triggers will be. On one view it’s only when there is a physical shortfall in the market, and that won’t be for a few years if at all.
However, it clearly increases risks and pressures on the exporters. Note that the exporters essentially include the Chinese and Malaysian Governments and they won’t be happy about rules being changed halfway into “the game”.
As the background analysis below discusses, all of the LNG exporters have some residual concerns about their reserve adequacy, but GLNG has a clear problem and has had it for years.
We expect that in the end if push comes to shove all that will happen is that than an exporter (GLNG by far the most likely) will just purchase LNG on the spot market to fulfill its contracts and divert the gas it would have used back into the domestic market.
As there is no suggestion of price limitation, we expect that the domestic price of gas will continue to trade at around export parity.
We do not see this policy as impacting much on the relative merits of building new gas fired generation except to say that if the country needs Government regulations to stop us running out of gas given existing demand, it’s hard to see new gas fired power stations being built in the near future.
The gas price will likely continue to be driven by the oil price. Higher oil prices incentivise new development and exploration and make more marginal resources profitable. Secondly gas demand and price in Australia are seasonal and will increase in winter.
We expect that if prices go high enough either Shell or Origin can relatively easily make some LNG labelled gas available to the domestic market. But they will ration supply to maximise price and profit. This policy announcement doesn’t change that.
Down the track, the chances of an East Coast LNG facility being built likely increase. The next development to look for is whether the NSW Government approves the Narrabri CSG development. Expect Alan Jones and the anti gas environmentalists to continue their unlikely and perverted alliance to prevent this.
On the east coast there are three LNG producers. Some statistics are:
Note that we have only compared reserves with LNG export contracts. Some reserves are also required for various domestic contracts, for instance QCLNG has a 20 year contract for about 30 PJ per year with AGL (although some of that was resold to QCLNG and some has been sold to GLNG) and APLNG has various contracts principally with its 37.5% shareholder ORG but also with GLNG. (See Fig 2)
The 1500 PJ of gas can be compared to about 550-600 PJ per year of domestic (ex WA) demand.
The clear point is that GLNG, in which Santos has a 30% equity interest, doesn’t have sufficient reserves to fulfill its sales contracts and has been buying gas out of the domestic market to produce LNG.
In our view Santos always intended that one outcome of building LNG capacity in QLD would be to raise domestic gas prices. After all ,at one stage AGL was able to buy 400 PJ of gas from BGC for just A$2.50 GJ (real). However, in the event GLNG’s reserve development particularly along the Roma shelf and also at Arcadia has been below expectations causing problems for all concerned.
So GLNG has put in place a range of 3rd party contracts to meet the shortfall. A summary of these contracts is shown below:
If I owned GLNG I’d be worried about some of these contracts/heads of agreement. Senex is not yet producing gas from its project and recent announcements suggest lower rather than higher production rates.
Not much public information is available on the Meridian JV but its reserves are arguably out of the known sweet spot. However those projects don’t represent diverted gas. The key contracts that have caused the domestic price to rise are (i) that Santos sold essentially all of its Cooper Reserves to GLNG (the Cooper Basin historically supplied the bulk of NSW and South Australian demand) and (ii) “other” suppliers.
We think other suppliers likely includes parties such as Engie (Pelican Point) and gas otherwise intended for Swanbank E. The AGL sale is of gas coming from QCLNG and the Origin gas is gas that Origin is entitled to from APLNG and was originally intended to run Darling Downs power station.
In summary, GLNG must have some worries about its future supplies and certainly doesn’t have any surplus gas to divert to the domestic market.
It remains the case that the domestic Australian market is largely dependent on Bass Strait gas and that even there production costs are rising. Still, in a real physical emergency the QLD LNG gas could be diverted South.
Not all reserves are equal
CSG (coal seam gas) reserves are typically measured on a 2P (proved and probable) or 3P (proved, probable and possible) basis and are determined after looking at the cost of extraction relative to the market price of the gas.
It’s not realistic to prove up CSG reserves to the 1P (proved) category because of the vast number of wells that would be required. CSG reserves are determined by looking at the amount of coal and measures of the gas contained within the coal. Another relevant parameter is the willingness of the gas to flow from the coal once the water is removed.
The faster it flows the more gas per well per year but the sooner it will be exhausted. From a cash flow point of view cash at the beginning of a project is more valuable than cash in the future.
Broadly speaking, the CSG wells in QLD divide into two groups: those in the Bowen Basin (high reserves per well, steady annual production over an extended period but lower peak flow rates) and those in the Surat Basin (higher peak flow rates but faster decline rates). APLNG has a mixture, QCLNG is mainly Surat wells and GLNG is largely in the Bowen.
The point of this is that as the existing wells decline more have to be drilled, and there is always some residual uncertainty about the reserves per well and flow rates of the new wells.
Generally, it’s expected that on average the well economics will eventually start to decline. That is after having initially moved down the learning curve and lowering costs eventually costs will start to rise again. Because of their contractual commitments all the LNG producers and investors have to keep a close eye on how strong reserves really are and how economic it will be to produce them in 15-20 years time.
The LNG producers sell the vast majority of their gas under typically 20 year contracts linked to the oil price. At the time the contracts were written the slope (ratio of LNG price in US$MMBTU to US$ oil/ b) was around 14% and the oil price was US$100 A$1=US$1. There are about 1.05 MMBTU per GJ. So the gas export sales price was expected to be around A$13.5- $14.5 GJ even $17 at one point in 2013.
However, at US$50 oil and even with a lower currency the price is just A$8.90 GJ (at the Curtis Island wharf). Spot sales price in Japan is even lower.
Of course, these prices are still way higher than the US gas price currently sitting at US$3.26 MMBTU and the European LNG spot price sitting at less than A$7 GJ. As such there remains pressure on the Asian price as US exporters try to take advantage.
David Leitch is principal of ITK. He was formerly a Utility Analyst for leading investment banks over the past 30 years. The views expressed are his own. Please note our new section, Energy Markets, which will include analysis from Leitch on the energy markets and broader energy issues. And also note our live generation widget, and the APVI solar contribution.
David Leitch is a regular contributor to Renew Economy. He is principal at ITK, specialising in analysis of electricity, gas and decarbonisation drawn from 33 years experience in stockbroking research & analysis for UBS, JPMorgan and predecessor firms.