Conference notes: Gas Asia Summit

More of a buzz than usual at the Gas Asia Summit in Singapore this year. Gone were long faces about low prices — indeed, the big players in LNG seems to have forgotten the supply glut ever happened. The mood was upbeat: not quite business as usual, more like a shot of strong coffee after a heavy night out. I had a feeling that people were rolling up their sleeves having made some big decisions. GAS was part of Singapore International Energy Week (SIEW) and as ever the island is buzzing.
This conference had three big takeaways for me:
Canadian LNG is no longer a pipe dream. It will happen, and it will probably be on a big scale. The Shell FID gave a clear signal that, despite the complex permitting process, it can be done. A Canada spotlight panel reckoned that Canada could have 5-12 liquefaction projects up and running by 2030, on both the east and west coasts. Exports will be of the same magnitude as those from the US, Qatar or Australia.
LNG in shipping is becoming a reality. Shipyards are busy preparing vessels for the IMO 2020 regulation, but older vessels will be scrapped rather than retrofitted. The next generation of boats will be dual-fuelled or LNG ready, but the yards also have orders for LNG-fuelled vessels from barges to tankers. What we are seeing now is the seeds of a new industry. This is no longer something that is waiting to happening, it is happening now.
Islands are getting smart about energy. Advising SIDCs on fuel supply has always been my idea of a dream job, and I met a gentleman who was doing just that over lunch. LNG is the fuel of choice, as it ticks all the boxes: lower carbon than diesel, energy intensive, resilient and with lower investment cost than alternatives such as energy storage.
Mega-trends
After a conference, it’s important to think about what was not said, as well as what was said. Were there elephants in the room that no-one talked about? Yes. A whole herd of them. Here are just two:
The benefits of LNG vs diesel are crystal clear, but I felt that many in the gas industry were in denial about the potential for energy storage. Maybe batteries are the next big story, despite all the skepticism. Lithium has already had its first supply shock, after prices soared above $20,000/t a couple of years ago because supply couldn’t meet demand. The battery brigade are already looking at lithium alternatives such as selenium, costs are declining, and battery life and range improving. It cannot yet replace gas as a backup fuel for intermittent renewables, but by 2030? Perhaps.
King Coal has lost its crown, but no-one seems to entertain the idea that coal might make a significant comeback. I never understood the idea of Clean Coal, but if Carbon Capture and Use (CCU) were possible on a large scale, it would be a game-changer. Researchers are looking into ways to solidify emissions and potentially also finding uses for the solids. The dash for gas in China and India has been driven as much by air quality concerns as GHG emissions. CCS as a carbon disposal technology remains out of reach, but CCU could be a game-changer.

Energy storage may be a Black Swan for gas demand

The article below appeared in the September 7th, 2016 edition of Natural Gas Daily, a specialist newsletter published by Interfax, focussed on the global natural gas and LNG industry.
 
Energy storage can be used to bridge the intermittency of renewables such as wind and solar, making it a potential competitor to gas, which is typically used to meet mid- and peak-load power demand. Gas-to-power has been a growth market for LNG, particularly in countries such as the UK, where intermittent renewables form a significant part of the energy mix.
The energy storage industry is in its early stages, but it is growing rapidly. Bloomberg New Energy Finance (BNEF) predicts investment in energy storage will exceed $8 billion per year by 2024, a sixfold increase from current levels. The BNEF forecasts that Japan, India, the United States, China and Europe will account for 71% of global installed energy storage in 2024. The Energy Storage Association has predicted storage on the US electrical grid will increase 10-fold by the end of the decade.
Storage exists in several main forms: pumped hydroelectric storage is the most widely used technology, in which water is pumped uphill behind dams and then released, turning turbines which generate electricity.
Best-known to the public, however, is large-scale chemical storage – including batteries such as the Powerwall, unveiled last year by US entrepreneur Elon Musk. The Powerwall is a rechargeable lithium-ion battery for homes, but Musk’s company Tesla has also developed the PowerPack – a 100 kWh battery that can supply electricity on the same scale as a small utility. Tesla is building what it calls a Gigafactory in a 1,300 hectare area of the Nevada desert near Reno that will provide 35 GWh of lithium-ion battery power for new electric vehicles by 2018. The $2 billion project aims to produce enough power to charge 500,000 electric cars per year.
Other storage technologies involve the use of compressed air or flywheels to provide power when generation from intermittent sources drops. Thermal storage using concentrated solar power has also been developed where the climate is suitable. All these options are technically feasible, but their main drawback is that they are costly compared with conventional generation.
Energy storage can be located in the generation and transmission part of the supply chain, often called ‘in front of the meter’, or at the site of final consumption – for instance at a utility customer or at a corporate site with solar panels – often called ‘behind the meter.’
Investment across the supply chain
Investment in energy storage is likely to be made across the supply chain from generation to consuming sites. Generators look at energy storage primarily as a technology to balance the system, by deploying batteries rapidly when renewables generation is low. Consumers use energy storage within distributed electricity systems to ensure stable power supplies to their own sites.
When combined with demand-side management systems and smart grids, which allow peak power demand to be shaved by reducing supply to those who do not need it, electricity storage could significantly alter the profile of power sector demand for conventional fuels. This could have a notable impact on the growth of gas-to-power demand, even when gas prices are favourable.
Last month, a National Grid competition to provide 200 MW of power to balance the UK power network was dominated by battery projects tied to intermittent renewable sources such as wind. The Pen y Cymoedd onshore wind farm in Wales, which is due to be completed in 2017, will have a battery on site able to deliver 22 MW of power when the National Grid needs it. This may become a template for the design of new renewable generation facilities.
Energy storage already has a foothold in the US, almost entirely in the form of pumped hydroelectric systems. The 21 GW of installed capacity represents just 2% of peak demand, but the rapid growth of wind and solar in states such as California is driving the need for the expansion of energy storage. The California Energy Commission estimates the amount of wind energy generated doubled between 2010 and 2015 to reach 8.2% of the state’s power mix, while solar rose from virtually zero to account for 6% of over the same period.
Cost will be critical
How big the industry will become depends largely on the evolution of costs. The Electric Power Research Institute (EPRI) has forecast that lithium-ion battery packs will drop to one-quarter of their current price by 2022. The EPRI has released simulation software that it says provides a solid foundation for evaluating where the use of energy storage makes sense in the national grid. The EPRI used the software to model the viability of energy storage for the California Public Utility Commission.
Other studies have shown that energy storage remains significantly more costly than gas in terms of providing a backup for intermittent renewables generation. Investment bank Lazard produced a report in November 2015 that made levelised cost comparisons between lithium-ion batteries and conventional generation, specifically diesel and gas plants geared to manage peak-load demand. It found that the battery costs were in the range of $321-658/MWh compared with $165-218/MWh for gas peaker plants, and in the range of $351-838/MWh compared with $212-281/MWh for diesel in the commercial and industrial sector.
The study, which provided similar cost comparisons for other battery types, found no energy storage source was currently “in the money” compared with gas and diesel. But it said combinations of storage technologies were within “striking distance” of competing with conventional fuels.
If the sharp cost reductions seen in the growth of solar photovoltaic cells were replicated in energy storage, there is a real prospect these new technologies would make significant inroads into the market share of gas in the power sector.
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