South Asian liquefied natural gas (LNG) markets stand to benefit from the recent shift to a globally oversupplied and lower-priced environment that has resulted from a mild winter and recent supply additions, particularly in the United States.

Bangladesh could see LNG demand grow by 1.9 million metric tons/year (mmty) at current price levels, as gas availability issues during the last fiscal year (October 2017-September 2018) meant that around 13 terawatt hours (TWh) of existing generation were reportedly lost and replaced with oil-fired generation, according to Energy Aspects. The country burned 17.2 TWh of oil-fired generation during that time, while gas-fired power plants had a utilization level of just 30-40%.

“…Simply resolving those gas shortages would push oil out, leaving a mere 4 TWh of oil to be replaced with gas,” Energy Aspects analyst Trevor Sikorski said.

And while that 4 TWh of oil volumes would be hard to replace due to needs to meet peak demand, the current drop in spot LNG prices, which are at multi-month lows, “would allow Bangladesh to buy sufficient gas to alleviate the existing constraints,” he said.

While China grabs most of the headlines when it comes to LNG demand, smaller countries like Bangladesh have been seen as opportunities to develop and expand markets. In its most recent energy outlook, BP plc said the dominant market for gas exports will continue to be Asia for the next 20 years, although the pattern of imports shifts, with China, India and other Asian countries overtaking the more established markets of Japan and Korea, and accounting for around half of all imports by 2040.

Like Bangladesh, Pakistan has also had gas availability issues in the past, but with its shift away from oil a government priority, the country has brought online three new combined cycle gas turbines (CCGT) since the start of 2017. At a combined 3.6 gigawatts (GW), the country now has sufficient gas capacity to replace all 43 TWh of power generation coming from liquids, according to Energy Aspects.

“That would provide demand for an added 3.6 million tons of LNG and, as LNG prices fall and oil prices rise, the economic case for that switch is becoming stronger,” Sikorski said.

Pakistan reported record LNG imports in 4Q2018, but there are other factors to consider in the country, Energy Aspects said. While phasing out oil is expected to boost gas demand, significant hydro capacity additions are also expected (10.9 GW through 2025), as is a build-out of coal-fired capacity (9.3 GW.) This makes Pakistan’s future reliance on gas for power generation “far from certain.”

Meanwhile, the uptake of gas in 2019 and 2020 relies on sufficient gas infrastructure. In early 2019, a shortage of gas-fired generation intensified due to the cancellation of spot LNG tenders in 2H2018 and storms in early February, according to the firm.

“This meant supply was interrupted for the three new CCGTs for around a week in February, also affecting the fertilizer and compressed natural gas industries. The three new CCGTs are in the north of Pakistan, so the gas shortages fell hardest on those plants given their distance from the LNG landing point,” Sikorski said.

While the gas shortages should begin to get resolved with the end of the heating season, LNG imports will be constrained by the 10 mmty of existing regas infrastructure. “With 2018 imports at 6.1 mmty, some upside to imports certainly exists, and the underlying push to get oil out of power should continue to support LNG demand growth,” according to Energy Aspects.

In India, gas demand growth for power generation is even less clear, limited by gas-fired power capacity and potentially regasification capacity. The Central Electricity Authority (CEA) put the level of installed gas capacity at 24.8 GW at the start of 2019, although it is not clear if that includes the 9 GW mothballed due to lack of gas supply, according to Energy Aspects.

“Taking all 24.8 GW as dispatchable power, that would give a baseload generation of 175 TWh,” Sikorski said. “Calendar year 2018 saw gas contribute 50 TWh, the same level it has contributed since 2016, which means a maximum of 125 TWh of additional generation is possible from existing capacity if gas is turned into a baseload power source,” Sikorski said.

With hard coal-fired generation at 987 TWh in 2018, that switch would only involve the displacement of some 13% of Indian coal-fired generation. If all 125 TWh were realized, that annual increment would support an increase in underlying Indian gas demand of 17.5 million tons,” according to Energy Aspects.

Meanwhile, India has some 68.7 GW of thermal plant under construction, but almost all of that is coal-fired. Some 34 GW are expected online from 2019 through 2021, and of those, only 0.4 GW involves a gas-fired plant.

“That growth, even if plants are delayed beyond the expected schedule, will be enough to satisfy the requirements of power demand growth and meet what is left of unfulfilled demand,” Sikorski said.

In previous years (when unfilled demand was significant), gas just had to be low-priced enough to recover its costs through the power tariff base. But now, gas must compete directly with coal to get any purchase in the power market, according to Energy Aspects.

The other headwind — both economic and regulatory — is getting a coal-to-gas switch to actually happen, the firm said. In general, Indian domestic coal is priced low enough that plants using such coal will likely not be the ones to switch to gas, as issues such as any Indian rupee depreciation will continue to favor coal.

Meanwhile, the Indian government is trying to get gas into the urban gas sector (residential/commercial and industry) rather than into power, which could lead to a slower increase in gas demand in India than what has been seen in China.

Furthermore, India’s LNG imports during the coming two years are also likely to be highly sensitive to the ramp-up in new terminals, which in turn depends on the alleviation of downstream infrastructure constraints.

The country has 15 Mtpa of capacity at three terminals that have infrastructure constraints for various reasons and at different time periods, while 11.5 mmty of new capacity is expected to be completed by the end of June. This includes volumes through the 5 mmty Mundra facility, which has seen its start-up delayed due to various contractual disputes. The 4 mmty Jaigarh terminal also has downstream infrastructure that needs completing. Only the 2.5 mmty third phase expansion at Dahej would go into a well-connected part of the Indian grid, according to Energy Aspects.

Without those constraints alleviated and a successful startup of the planned terminals, “India will physically not be able to provide any demand-side response, even if gas prices fall to levels that would make economic sense,” Sikorski said.

That’s not to say India’s appetite for LNG isn’t there. In February, a unit of India’s Bharat Gas Resources Ltd. signed an SPA to take 1 mmty for 15 years. Also last month, Houston-based Tellurian Inc., which has the Driftwood LNG export project on the drawing board, said it has a memorandum of understanding with India’s Petronet LNG Ltd. India for a potential investment.

In other news, Houston-based Cheniere Energy Inc. on Tuesday received FERC approval to start service from Train 5 at its Sabine Pass LNG export facility along the U.S. Gulf Coast. The Federal Energy Regulatory Commission’s approval was based on staff inspections and review of information filed earlier this month. Cheniere reported last week that Train 5 was substantially completed.

On Monday, FERC gave the green light for Cheniere to introduce feed gas in support of commissioning activities for Train 2 at its Corpus Christi LNG export facility in South Texas, and earlier this month, the Commission approved the start of commercial operations for Corpus Christi Train 1.