Can gas challenge coal in Asia?

Asia’s electricity consumption increased by 4.5% year-on-year in 2016, with natural gas consumption increasing by 3.6%, and with average forecast annual economic growth of around 6% over the next five years, and given the strong correlation between economic and consumption growth, we should expect these consumption growth rates to continue. The question facing Asia is how will this demand growth be met while also meeting medium term climate objectives as set out in the Nationally Determined Commitments submitted as part of the Paris Agreement.

For a region that is heavily dependent on coal and with a poor pipeline natural gas network the obvious answer should be liquefied natural gas (LNG). Not only is there abundant LNG supply but the emergence of an increasingly actively traded spot market accounting for around 10% of LNG trade has driven down the price of spot LNG below $6/ MMBTU compared to the $16-18/MMBTU paid by Japanese utilities post-Fukushima.

LNG could, and should, become Asia’s primary baseload generation fuel in the medium to longer-term. With dwindling political support for nuclear investment outside China and with increasing investment in intermittent renewable generation resources, and particularly solar, gas-fired plant provides both the baseload supply and an efficient back-up resource for intermittent generation. And from an environment perspective the emissions from an advanced CCGT plant are less than half that of ultra-supercritical coal-fired plant.

But however persuasive the case for turning to gas may be, Asian energy policy appears loath to walk away from coal. Indeed, some countries are increasing investment in new coal-fired plant. Japan and Vietnam are primary examples of a pro-coal policy, while China, Asia’s largest coal consumer, is actively pursuing policies to reduce its coal dependence.

Japan is a developed economy, but fuel import dependent. Post-Fukushima the utilities most impacted by the loss of nuclear load, such as Tokyo Electric Power Corp., invested in LNG as the primary thermal replacement. Entering into long-term oil- indexed LNG supply deals these utilities had to ramp up electricity tariffs or write off huge losses based on the cost differential between the operation and maintenance cost differential between nuclear and gas.

In 2017 Japan’s government revised its 2030 generation target shares to LNG 27%, coal 26%, nuclear 22%, renewables 22% and oil 3%. Under this plan, which is dependent on the nuclear regulator approving the return of plant closed for safety reviews post- Fukushima, coal-fired plant will contribute 56% of baseload with the balance provided by nuclear, hydro, geothermal and biomass.

There is a total of 43 potential nuclear reactors that could become operational again, with regulatory assessment taking up to two years. Currently the regulator has assessed 26 reactors with only five passing the assessment. Given the uncertainty over the return of nuclear capacity a number of utilities have had to source baseload alternatives, with deregulation of electricity supply in April 2016 also encouraging utilities to look at more cost- effective power resources. The result has seen several new coal-fired plants being planned with 17 GW of capacity currently at various stages of development. But there are two conditions that have to be met for new coal- fired projects: first, the new plant has to utilize best available technologies, which means only ultra-supercritical is eligible, and second, the plants emissions have to be consistent with the government’s 2030 targets, meaning a 1 GW plant has to achieve a 45% gross energy efficiency.

With demand growth forecast at almost 11% over the next few years there are concerns that Vietnam will struggle to meet demand in the short-term until new capacity comes online. With the country relying on hydro for around 45% of electricity supply Vietnam depends on favourable hydrological conditions to meet demand. Medium-term demand growth will be met by investment in new coal-fired capacity, with three plants (two 1.2 GW and one 1.32 GW) expected to be operational by 2021-22. As a consequence, Vietnam’s coal share of generation is expected to marginally increase above 30%.The planned development of a competitive electricity market by 2021 could also encourage more investment in cost-effective coal plant providing the cumulative emissions meet the government’s targets.

China is synonymous with coal, being both the world’s largest producer and importer. But with high pollution from coal plant emissions Beijing has initiated policies to reduce the share of coal in the generation mix, including a moratorium on new coal plant build. In 2017 the National Energy Administration (NEA) ruled that 28 of China’s 31 mainland provinces do not currently have the right financial or environmental conditions to build new coal capacity based on a ‘traffic light’ system introduced by the NEA in 2016 to prevent aggravation of China’s coal overcapacity crisis. The system assigns each province a colour to signify the viability of its coal pipeline — based on profitability, existing capacity and ‘resource constraints’ such as air pollution and water.

Red means no new coal projects should be permitted, orange indicates local governments and coal companies should tread carefully, and green says that there is plenty space for new coal power. Currently 24 provinces have been issued red lights, 4 have been issued with an orange light (which recommends not adding coal in much stronger language than last year) while only two have received a green light.

While China is curbing further growth in coal demand, the country’s robust demand for electricity will maintain the reliance on coal firing. If we assume that all new demand is met by investment in gas, new nuclear and renewables then coal’s displacement will be a function of demand growth.

Displacement of coal plant by gas in the medium-term is extremely unlikely, and as markets become more competitive coal becomes more attractive as a low-cost resource from an O&M perspective. But a competitive Asia gas market would challenge this scenario, and such a market is in the embryonic development stage.

By the end of 2018, Singapore’s LNG send-out capacity will exceed domestic requirements, with a secondary gas market also currently being developed with an expected launch in 2019. Add in a competitive gas supply market in Japan since April 2017 and competition between Singapore and Japan to be Asia’s gas hub and the development of gas-on-gas pricing early in the next decade becomes feasible. And if the price of carbon were to increase towards $20-30/tonne then the case for gas in the generation mix would be further economically secured. But maybe this is wishful thinking. 

*Jeremy Wilcox is managing director of the Energy Partnership, an independent Thailand-based energy and environment consulting firm.