Two recent stories from Japan’s energy sector provide book-ends in terms of risk on the range of approaches the energy poor nation is currently pursuing to source natural gas.
The first was news late last week of a successful production test from methane hydrates deposited in the sub-sea environment off Japan’s Pacific coast. Details were scant – no flow-rates were quoted for example (cost was mentioned – US$180M, financed by the Government). A photo would be nice – but might look disappointingly small.
This test follows on from one made about 4 years ago (which at the time was at least partially financed by private sector company JAPEX – who appears to have dodged a cost bullet for the mother country this time). That test lasted a week and was interrupted by sand flowing into the well. The latest tests involve two new well designs.
Early days it seems. However, the resource size is enormous and the will of Japan Inc is being applied with some vigour. A low probability risk to the LNG industry perhaps – but a high impact one.
The other Japanese story was more prosaic – Tokyo Gas buying a 30% equity stake in a small US gas producer with acreage and production in the Haynesville on the Gulf Coast. Japan Inc is used to vertical integration in LNG mega-projects and this is a natural follow on for the more liberal GoM liquefaction plants and their tolling services.
Crude prices bounced back somewhat in overnight trading from their recent large falls, with Brent up ~0.7% to US$49.44 and WTI up a similar quantum to US$46.50. News from the Saudis about the high probability of extended OPEC (and Russian, for what they are worth) cuts into 2018 provided the bullish impetus.
Henry Hub fell ~3% to US$3.17.
LNG and international gas
The rise of potential new West African LNG hubs continues – with recent news of a major resource extension (a cool 15 Tcf) for Senegalese gas from BP and Kosmos. Regional resources (in good quality reservoirs, albeit being fairly dry) are now in the 40 Tcf range. This is less than East African resources in Mozambique/Tanzania – but sovereign risks may well be less.
There seems to be a lot of gas in the world. If more African gas had been discovered last decade, there would likely be no liquefaction trains in Queensland and East Coast Australian gas prices would be markedly lower. We don’t buy the argument from some that CBM in Queensland would never have been developed if not for LNG projects – production was occurring for many years before then. The more realistic argument is about the timing of production and when lower quality fields would ever have come on.
Origin Energy (ORG) has just entered into a PPA for a large wind-farm at a price reported to be less than A$60/Mwh (inclusive of payments for renewable energy credits – so directly comparable with fossil fuel prices). Current gas prices in Australian cannot compete with this for base load power – rather gas’ value is its flexibility rather than its absolute volumetric contribution.
Company news – Arrow Energy
The 50/50 Shell/PetroChina Arrow Energy joint venture has announced more investment into its Southern Queensland CBM fields – increasing production from Tipton field by 40 TJ per day. Locationally this is best placed to serve Shell’s LNG plant in Gladstone – but should provide some loosening of the overall market, thereby providing some assistance to the domgas market in physical if not dollar terms.
Quote of the day
OPEC’s next formal meeting is due in Vienna in the last week of this month. UBS analyst Giovanni Staunovo recently outlined the Goldilocks-like challenges facing the organisation:
“The risk of a higher cutback is that it could trigger too strong an increase in prices and support U.S. shale. If they change strategy, Saudi Arabia would lose face. You can’t say you want lower inventories, and after a few months give up.”