Published in the May/June 2015 edition of RESOURCESTOCKS
The Australian east coast gas market has been hurtling towards a supply shortfall. Massive new LNG plants with a shortfall of gas supply capacity, declining legacy conventional gas assets and high costs and regulatory blockages to developing unconventional gas have conspired to paint a picture of less gas available for domestic use and higher prices.
However, the landscape keeps changing. A combination of high domestic input costs and up until recently a high Aussie dollar, combined with poor public policy, is killing Australia’s manufacturing industry, resulting in reduced gas demand. In addition, rising utility costs for energy generally and a switch away towards more renewable energy sources has also dampened demand for gas.
The purchase of BG by Shell also tightens up the domestic market, with Shell’s coal seam gas (CSG) reserves now likely to be earmarked for long-term processing at BG’s QCLNG project, rather than for supplying domestic users or other LNG projects.
BG’s QCLNG project has commissioned one LNG train which will be followed by five more processing trains, including a second at QCLNG and two more at each of Origin Energy’s APLNG and Santos’ GLNG projects.
StockAnalysis* believes that there has been billions of dollars wasted on duplication of infrastructure for these projects. I’ve seen estimates that up to $5 billion could have been shaved off capital costs if some common sense and common infrastructure had been employed!
Here’s the interesting bit. GLNG has sold a total of 7 million tonnes per annum of LNG over 20 years on contract to Korea’s Kogas and Malaysia’s Petronas, but the start date for these contract sales is not clear and could be out into 2017. With spot LNG prices ranging around $US7.10 per gigajoule and current contract sales likely to be set at $8.70/GJ, Santos might be forced to offload early product at a substantial loss into an oversupplied and weak spot LNG market. With all-up delivery costs likely to be about $10.50/GJ, or equal to about $70 a barrel, the GLNG project would face a significant cash challenge at current commodity prices.
In addition, the APLNG project holds contracts over 7.6Mtpa of LNG, with 4.3Mtpa of that total set for delivery from mid-2015. This early contracted LNG volume could be met by the output of just one of the two processing units currently under construction.
Completion guarantees on processing plant ensures that each new LNG train will need to undertake a period of commissioning to the satisfaction of owners. After that things could get interesting. Origin and Santos could lose less money on these unprofitable projects in the current market by simply buying LNG on spot and trading it into any contracts that must be fulfilled.
StockAnalysis can see a situation where once commissioned, the Gladstone-based LNG plants could run at less than designed capacity until gas prices recover to over $11/GJ. Individual trains may even be shut down for a period if contracted gas can be met with limited supply from Gladstone, combined with spot market trading.
Domestic supplies are still likely to become tight into 2018, when the oil price should have recovered and LNG trains are operating at full capacity.
Companies with gas development projects, including AWE, Cooper Energy, WHL Energy, Real Energy and Senex Energy and possibly Beach Energy and 3D Oil, could find themselves in the box seat, but the journey will be rough.
In its latest productivity report, the US Energy Information Administration estimates that oil production from the US’ major onshore, light tight oil (LTO) and gas sedimentary basins will fall by 57,000bbl per day in May, compared with April. Despite an average increase of 13bblpd from each new well completed compared with previous wells, a rapid fall in total wells being completed will see production falling in every basin except the Permian and Utica Basins.
A shift to the application of horizontal well completions in the Permian Basin will result in increasing overall output from the region in May, even as the number of wells declines. A rapid expansion of activity at sweet spots in the Utica Basin will protect this region from decline for the month of May. However, StockAnalysis expects that all regions will be in rapid output decline by July.
Oil and gas drilling rig data out of North America continues to show dramatic declines in activity with oil directed rigs down 46.5% over the past year to 802 and gas directed rig numbers down 30% to 222 rigs.
StockAnalysis expects that OPEC will try to keep the Brent oil price below $60/bbl for as long as it can so as to inflict as much damage as possible on the over-geared US LTO industry.
As US LTO companies move to get their year-end oil reserves certified, StockAnalysis expects a massive evaporation of 2P oil reserves under the influence of a weaker and sub-economic oil price stack.
Proven and probable oil reserves are based on geological factors and oil in place, recovery factors, costs associated with extraction and estimated prices going forward. The geology is exactly the same as 12 months ago and while costs may have fallen 30% over that period, the big negative movers have been the tumbling prices of oil and gas.
Reserve certifiers may have been happy to sign off on 2P reserves when the oil price was $110/bbl, but with West Texas Intermediate at $52/bbl and gas at $2.52 per million British thermal units, get ready to see a surprising vanishing act.
Previously certified 2P oil will now be classified as contingent at best, smashing lending covenants to a cohort of over-leveraged LTO developers and producers.
Companies have already begun to scramble to cover bank debt with bonds and notes.
Banks that lent on the basis of the net present value of certified 2P will now want their money back, so debt that might have cost 5% per annum is rapidly being swapped out for notes costing upward of 9% per annum, if they’re lucky!
*Strachan is author of StockAnalysis.com.au and the "Taking Stock" columnist for RESOURCESTOCKS magazine.
