APA. The gas transmission ring master
APA owns around around 75% of the 20,000 km of gas transmission pipelines in Australia. The scope of its business is illustrated by CEO, Mick McCormack’s pride and joy, the pipeline map of Australia.
However, length is not the main indicator of value, and these days 1/3 of APA’s business value consists of acting as the owner but conceptually lessor of the leveraged finance lease of the 543 km QCLNG gas pipeline. APA paid US$5 bn for this pipe in Dec, 2014.
For all intents and purposes, the QCLNG pipe is a very low risk business in that the revenues, opex and interest costs are essentially locked in for the life of the gas fields supplying the plant. In addition to its gas pipes, APA owns the Diamantina gas fired power station (supplying Mt Isa), gas storage, and a wind farm in West Australia, and it manages and has an equity interest in two interstate electricity transmission businesses.
Guidance from management
APA guides FY17 ebitda to be $1.425 to $1.445 bn (a narrow range which investors love because it demonstrates the low risk) and up $100m or 7% at the midpoint over FY16. Net interest is guided to a midpoint of $515 m up just $8 m on FY16. Distributions are guided to 43.5 cents up 4.8% on the PCP and putting APA on a yield of 4.7%.
ITK notes that gas transmission investment opportunitites are thin on the ground. Management would like to move more into owning gas processing plants and has also indicated its interest in moving into owning and developing renewable assets. APA’s key strength is its low cost of capital so we think any renewable asset will need a good PPA. And it’s PPAs that are in scarce supply. The first development will likely be a 40MW solar farm in WA at Badgingarra.
The broader market’s interest is in APA’s “influence” on the East Coast grid.
As gas has become scarcer and gas prices have risen fingers get pointed at APA as somehow being to blame. The ACCC and the AEMC have both inquired into gas transmission and the gas market in the past couple of years and now COAG has adopted a set of reforms.
The key changes to be implanted are;
- Set up two gas trading hubs (one in Qld at Walumbilla, and one in the South). Notably Moomba won’t be a hub. Bad luck Santos. At the moment we can’t see how this in itself will make much difference.
- Set up a spare transmission capacity market. At the moment the majority of the East coast pipeline capacity is fully “rented” to a few shippers, typically AGL, ORG, EnergAustralia and a few minor players. They rent the capacity all year round and it represents a fixed cost. This makes gas retailers the natural owner of peaking gas generation. A peaking gas generator is no use if it can’t get gas when it needs to run. Typically all the peakers want to run at once, so gas gets scarce and pipeline capacity scarcer. So a gas peaker has to rent capacity all year long even though it may only use it 5% of the time. A gas retailer already shipping gas through the pipe can spread this cost more efficiently. Now COAG will ensure there is a market every day for capacity that has been rented but is not being used. However the key for us is that at the moment is that the existing renters of capacity will not be forced to sell into that market. COAG will review the decision not to introduce a “use it or lose it” policy after a few years. Conclusion. We can only see this making a minor difference but it is taking some of APA’s influence away and it may, in our opinion, actually reduce the incentive for shippers to fund pipeline expansion because they may have to effectively onsell it at times its not being used.
- COAG plans to require all gas explorers and reserve owners to fully disclose their reserves and resources. COAG regards the gas market as secretive. That is no secret. Analysts have been complaining for many, many years that companies don’t disclose their resources. ORG only disclosed its true CSG reserves when it received a takeover offer from BG. But the biggest culprits in all of this, in our opinion are BHP and Esso in Bass Strait. There is next to no disclosure of what the “true” resources in Bass Strait are. Further there is next to no disclosure of the gas price in contracts. All that said, we aren’t convinced directives from COAG will do much to change things. Companies will just talk about resources being developed at certain prices. A better disclosure system in our opion would be for for the companies to categorise resources by price required to justify development.
Impact on APA negative but not that much and down the track
For the time being only a small minority of APA’s revenue comes from regulated tariffs. That’s because of so called “foundation contracts”. These are contracts between a shipper and APA under which APA agress to build pipeline capacity and the shipper agrees to rent the capacity for a set number of years. Most pipelines in Australian have been financed this way. In the early days the contracts were of long duration, 20 years and more. However in recent times contract durations are shorter. Leaving aside the QCLNG contract ITK believes APA’s average contract duration is in the 7-10 year range.
We think what happened with the Dampier to Bunbury pipe in W.A. (0wned by Duet) is a good example. Regulated tariffs tend to be lower than negotiated foundation contrac tariffs. When the foundation contract ends shippers will use the lower prices on offer in the regulated contract to negotiate better terms with APA.
The way for APA to avoid this situation is to keep expanding the gas pipeline network. The problem with this is that there are no new gas fields. Essentially all the gas in Eastern Australia is being sucked North. Qld gas goes to China and Japan. What’s left of the Cooper Basin gas goes to Qld and in part is exported. Cooper Basin gas used to supply NSW and South Australia but now these markets have to be supplied from Bass Strait and the Otway Basin. Bringing more gas to NSW from Bass Strait required expanding the the two transmission networks that ship gas North but this work has largely been completed.
Even assuming Bass Strait had the reserves to futher increase gas supply to NSW, the limit is Longford Gas processing plant capacity. There is absolutely no indication that this old plant will be expanded any time soon.
The potential sources of new gas we know of are:
- CSG reserves in QLD. There are reasonable quantities of CSG 3P reserves in QLD. Specifically Shell owns significant good quality reserves, 4000- 5000 PJ in the Surat Basin intended for its LNG plant. ORG has 800 PJ in the particularly economic Undulla Nose area. Still there are few public signs that these will be developed just now.
- CSG in NSW. In the end in our view this has been stopped more by wealthy landowners than environmental issues. It will need a big positive signal from State Government for these resources to be exploited. Further we think the cost of extracting the gas may be higher than those previously published by STO and AGL. Right now zero enthusiasm from AGL. STO may have it on the backburner (pun intended).
- Shale and tight gas in the Cooper. The cost of extracting this is high at present. We think well above the current $6-$8 GJ for contract gas in Australia
- Shale gas in the Northern Territory. This still seems a decade away.
- Minor reserves from Bass Strait and the Otway.
Gas generation has little future without a carbon tax
Experience in Europe and Australia shows that gas generation is the first casualty of increased renewables penetration. The gas lobby loves pointing out that gas is less carbon intensive than coal, and that is certainly true.
But its variable cost is also much higher than coal, in the absence of a carbon tax. Renewable energy, wind and PV has a very low marginal cost. Price competition is mostly decided on the basis of marginal cost. Gas loses that fight nearly every time (the USA right now is an exception). Unless the cost of extracting tight, CSG, shale, or conventional offshore gas, falls by more than the current estimates, it’s hard to see gas generation being economic in Australia. Over the past few years owners of three combined cycle generators (Pelican Point, Darling Downs and Swanbank) have sold their gas entitlements to the LNG exporters. That can’t be undone easily.
To put some context around this, replacing 5GW of coal generation in NSW and Vic with combined cycle gas would require about 4000 PJ of reserves. That’s most of the uncontracted defined reserves in QLD.
If there is a significant carbon tax, say $30/t, gas will struggle to compete with renewables + storage. The financier has to factor in the fixed costs as well as the variable costs shown in the figure.
The LNG plants are already taking about 90 PJ a month and this will increase to around 120 PJ a month by this time next year.
However, what we are most interested in is flows to NSW and South Australia. The way things are changing is perhaps best illustrated by Moomba to Sydney daily flows:
What we think may be happening now is that gas in Sumner is flowing North to be stored at Moomba (a hub after all) and then shipped back to NSW and Adelaide in Winter.
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.