ISLAMABAD: Liquefied natural gas (LNG) prices have come down and are falling continuously. Although current summer prices have a seasonal effect, there appears to be a constant trend as well.
Several policy issues have emerged in importing countries in the region which include whether long-term LNG supply contracts are advisable and is there a scope for renegotiating existing contracts both in price and non-price terms?
Last September, JKM-Japanese Liquefied natural gas prices varied between $4.50 and $4.90 per million British thermal units (mmbtu). In other regions, same prices prevailed.
Only a decade back, Liquefied natural gas prices were four times as much. Then some five years ago, three South Asian countries – Pakistan, Bangladesh and India – entered into contracts with Qatar at twice the current prices.|
Spot market is a relatively new phenomenon in LNG. Spot prices used to be higher than long-term contract prices until 2014. But as the spot market developed and its share increased, its prices decreased and are now lower than long-term prices.
LNG market has become very competitive with the entry of the US with its cheap shale gas resources and increase in general supply elsewhere. The US gas is competing with Qatar gas despite a considerable difference in distances.
India is lifting 50% of its LNG demand from the US, which earlier was a net importer suffering from short supply. It is now a big exporter.
Russian gas has also come into the regional market, creating a highly competitive environment and price and non-price pressures.
Another trend seems to be emerging, however, it is not sure if this will persist with the same intensity in future. Winter January 2019 LNG spot prices were $8.555 per mmbtu, which came down to $4.5 in July (summer).
Is it a seasonal effect due to lower summer demand in the West or it is part of the long-term decline or price adjustment? Will winter prices approach Qatar’s long-term price levels or even higher is yet to be seen?
Already, spot prices have recovered to $6.5. Lower prices will heighten the pressure to renegotiate prices. It would mean that the lower price trend is permanent.
Spot prices in Pakistan
In Pakistan, October LNG spot prices – based on last three month’s average Brent crude oil prices and the multiplier of 8.391% as opposed to Qatar’s 13.37% – were $5.2 per mmbtu as compared to Qatar’s contract price of $8.2837, which makes Qatar LNG prices 61% higher than the current spot prices.
The weighted average cost of LNG is $7.78. This average will go down as more and more spot buying is done to reduce the share of Qatar LNG. This will happen with the increase in demand.
Prevailing spot prices in India are even lower at almost 50% of Qatar-India LNG contract prices. Qatar’s long-term prices are becoming extremely unaffordable, both in India and Pakistan.
Qatar LNG prices are the same in both the countries, higher than international market prices and there is discontent over the issue in both the countries. The pressure on Qatar to adjust prices downwards is mounting, although price-opening clauses may be in its favour. In Pakistan, the share of LNG market was about 25% last year (2018-19). It is expected to increase in the long term with the exhaustion of domestic gas reserves.
However, the LNG demand has been low over the past months and one procurement bid has been cancelled recently. Power demand is much lesser than supply due to the addition of new coal and re-gasified LNG plants and because of seasonal factors as well.
RLNG-based electricity is expensive due to expensive LNG supply from Qatar at $10-12 per mmbtu. Had spot LNG been there at $5-6 per mmbtu, RLNG-based electricity would have been competitive and LNG demand would have been higher.
Knowledgeable people had opposed the installation of LNG and imported coal-based power plants at a fast pace, predicting excess supply. Had economic downturn not been there, even then, it is inconceivable that excess electricity supply could have been absorbed.
The government is considering cheaper electricity tariffs for the winter season. Perhaps early steps are required to retire inefficient power plants to face the demand-supply asymmetries.
Then there is back-to-back supply arrangement, penalties on non-or-short supply etc. Demand is variable, but contracts are for fixed quantities. The proposed privatisation of RLNG power plants is facing problems due to these issues and privatisation of gas companies will face similar issues.
LNG procurement by
The more urgent issue is created by the induction of private-sector parties in LNG procurement. There are no new consumers. Private LNG companies will take away consumers from the existing gas companies – the latter don’t like it and are resisting the move.
A possible solution could be a price equalisation charge on private-sector/spot LNG imports calculated on the basis of weighted average cost of LNG (Waco LNG). The surcharge will be paid to PSO, which is tied to long-term expensive LNG contracts.
This will bring down PSO’s cost by $2 on average, making RLNG competitive and pushing it lower in the merit order. This arrangement may have to be extended till 2025 when price negotiations would be due with Qatar.
A new LNG terminal policy has been announced. Private-sector LNG import provision has been on the table for quite some time now. This has not happened yet.
The CNG group appears to be the first to make gas supply to its members. This group will be able to procure at spot prices of $5-6 at least in summers as opposed to $10-12 average LNG cost of the two gas distribution companies – SSGC and SNGPL.
Clearly, this sector of the market can possibly be allowed to go to the private sector. However, if that is done, priority sectors like textile and fertiliser will also want to have the same facility.
Both fertiliser and textile exporters are already receiving gas at subsidised prices. Hence, it might be feasible to allow the two sectors to benefit from private-sector LNG.
The combined gas demand of the three sectors – CNG, textile and fertiliser – will be 9 million tons per annum (mtpa) – 20% of the total demand. The residual balancing may be done through taxation and subsidy.
There may be contractual issues (take or pay gas contracts of SSGC and SNGPL with domestic gas producers) that may have to be adjusted, realigned and streamlined. The gas transmission and distribution companies will get their T&D costs as per TPA rules.
Their net income may not be affected, although market share will. Thus, domestic, commercial, power and other consumers may remain within the domain of public sector.
The writer is former member energy of the Planning Commission
Published in The Express Tribune, November 4th, 2019.