A glut of new LNG supply coming on-stream after a relatively warm northern hemisphere winter has seen spot LNG prices plunge, putting a dent in the aspirations of the next generation of US LNG plant developers seeking to raise finance.
What has not upset the applecart is rising US gas prices. US gas production has risen almost inexorably despite low prices, benefitting from the co-production of gas with shale oil. Concerns had been raised that increased LNG exports, gas-for-power generation, gas use in refining and petrochemicals and other industries, as well as significantly higher pipeline exports to Mexico would combine to push up domestic US gas prices.
Not so, Henry Hub gas prices are bumping along below $3/MMBtu, while the sharp rise in flaring and venting in the Permian basin reflects not just infrastructure constraints, but the additional capacity of gas which could be brought to market – an estimated 661 MMcf/d in the first quarter, according to Rystad Energy. This would appear to support the new wave of US LNG projects which base their business cases on the expected long-term availability of cheap, essentially surplus, US gas.
US supply-side risk
However, just because concerns about higher US gas prices have not materialized does not mean they are misplaced. Surplus US gas is not simply a product of shale.
Canada has been slow to diversify its dependence of both oil and gas production on US markets, but movement is now taking place with a final investment decision (FID) taken on the 16.5 million ton per annum (mtpa) LNG Canada project last year. LNG Canada is focussed on new rather than existing gas production so will have little impact on Canada’s gas balance, but other planned LNG projects, particularly on the Atlantic coast, should.
Moreover, for years now, the US has been adding a roughly 50/50 mix of new gas-fired and renewable energy capacity to its electricity system. In April, the Energy Information Administration reported that gas-fired generation capacity had overtaken coal for the first time to become the largest source of electricity generation in the country. Since 2015, US coal-fired generation capacity has shrunk by 40 GW, while Combined Cycle Gas Turbine (CCGTs) capacity has increased by 30 GW.
There appears to be no end to this dramatic transition. In 2019, the EIA expects additions of 7.5 GW gas, mostly CCGTs, and 15.2 GW of wind and solar. Retirements are lower than last year, but a further 4.5 GW of coal-fired generation is expected to disappear and around 2 GW of older stream turbine gas plant, alongside 1.5 GW of nuclear. US gas for power generation demand will continue to rise as a result. Whether this increase in US gas demand, both for domestic use and export, can be sustained over the medium term without a rise in domestic US gas prices – and thus LNG feedstock prices – depends on the continued growth both oil and gas production.
Mid-2020s supply deficit
The possibility of higher LNG feedstock prices highlights just one of the US LNG industry’s vulnerabilities. While US LNG production is rising fast, there has also been a global rush to fill the expected supply deficit in the early to mid-2020s.
Novatek’s Yamal LNG plant is working overtime, producing above nameplate capacity of 16.5 million tons per annum (mtpa) in the first half to produce 9 mt of LNG. The company has also successfully sold 40% of its planned 19.8 mtpa Arctic 2 LNG project to various investors, putting it firmly on course for a positive FID.
Novatek has been buying up more northern acreage and could well realise its ambition of 70 mtpa by 2030, more from one company than most LNG producing countries.
This will add significant volume to the next wave of LNG production, which includes Qatar’s expansion from 77 mtpa to 110 mtpa by the mid-2020s and FIDs announced on additional US capacity, Anadarko’s Mozambique LNG, with ExxonMobil’s Rovuma LNG, also in Mozambique, likely to follow. As a result, the mid-2020s supply deficit looks slimmer every day. This is prompting a rush to FID while the window of opportunity remains open.
These international projects are more traditional in conception than the US LNG model. They are based on untapped dedicated gas resources which need to be processed, with the revenues from condensate production accruing to the project developer. There is no feedstock price risk because there is no competition for the feedstock gas supplying the LNG plant.
Moreover, many of these projects enjoy benefits which US LNG plants will not, for example proximity to Asian markets, which is expected to be the main centre of demand growth, high condensate yields adding substantially to revenues and in the case of Arctic LNG low temperatures which reduce the energy required to liquefy the gas. The US model in contrast is predominantly based on sourcing gas from the US gas system. As a result, and although barely apparent now, US LNG producers face more supply-side market risk than their competitors.
In this new era of LNG trade, producers are gambling that low prices will sustain market growth and deliver better returns in the future. Certainly, the direction of travel is positive, despite current prices. The depth of the opportunity represented by coal-to-gas switching is huge, particularly in China and South Asia, and delivers substantial greenhouse gas emissions reductions, positioning gas broadly on the right side of environmental regulation.
But, again, there are major uncertainties. Some LNG markets have proved fleeting. East Mediterranean gas has put paid to both Israeli and Egyptian LNG imports, US pipeline exports have eaten into Mexican LNG demand and, in June, Argentina exported its first cargo of LNG as Vaca Muerta shale gas gradually restores the country’s gas balance to surplus, a development which will also reduce LNG demand in neighbouring Chile and Brazil.
LNG market prospects are heavily dependent on new demand emerging not just from China, but from populous South Asia – India, Pakistan and Bangladesh. All suffer gas deficits and declining or relatively flat domestic gas production in the face of large latent demand.
However, all also suffer some major structural problems. Common is a lack of cost recovery in key gas consuming sectors such as fertilizer production and power generation.
The use of Floating Storage and Regasification Units, and their construction on a speculation basis, means a country’s entry into the LNG market can be rapid. However, once the immediate gas shortages in South Asia are met, the expansion of LNG demand in all three countries requires timely investment not just in LNG terminals, but inland pipeline networks, from large trunk lines to new customer connections.
An increasingly competitive international LNG market, rising feedstock prices and delayed demand are a combination which would provide a tough test for the US LNG model.
By Ross McCracken for Oilprice.com