UK unlikely to incentivise creation of new gas storage

The article below was carried in the 29 November, 2018 edition of Interfax’s Natural Gas Daily publication. The Interfax Gas Analytics service provides daily, weekly and monthly analysis of natural gas and LNG markets. 
 
By Peter Stewart, Interfax Chief Energy Analyst, Managing Director Interfax Europe Ltd
 
The UK government shows no sign of incentivising the creation of more gas storage capacity, despite calls to provide financial support for new projects after Centrica’s ageing Rough facility was shut down in 2017.
A UK parliamentary committee published evidence on 31 October on whether the country needed new storage capacity. It included submissions from consultants, transmission system operator (TSO) National Grid, energy-intensive industries, gas storage operators and the Department of Business, Energy and Industrial Strategy (BEIS).
The BEIS insisted that system flexibility is crucial. Dan Monzani, the department’s director for energy security, networks and markets, told the committee that market signals had successfully encouraged investment in LNG infrastructure, interconnectors and storage capacity over the past 20 years. “It is dangerous for government to choose what the best way of doing that is,” he said.
The UK has one of the smallest gas storage capacities of any European country, amounting to just 2% of annual demand compared with around 25-35% in major continental gas consumers. The UK uses around 78 billion cubic metres of gas per year but is able to store only 1.5 bcm.
Centrica decided to close Rough, which could hold 3.3 bcm, in July 2017 because the 32-year old facility was uneconomic and had become unsafe. EDF took a similar decision to close its Hole House storage facility a year later. Rough accounted for around 70% of the UK’s storage capacity.
Meanwhile, the private sector has proposed more than 15 gas storage projects in the UK over the past decade but almost all of them have been scrapped or are struggling to raise funds that would allow them to go ahead.
Uncertainty over the future availability of continental gas supplies during winter has risen in recent months because of the cap on output at the Netherlands’ Groningen field, the risk of a hard Brexit and political tensions over Qatar and Russia. The UK nearly ran out of gas when the ‘Beast from the East’ cold snap struck in March 2018. The sudden drop in temperatures caused a temporary spike in prices at the NBP hub, from around 60 p/th to over 270 p/th.
The UK depends on gas to produce half of its electricity, while 80% of its homes use the fuel for heating and cooking. Imports have risen as domestic production has dropped, leaving the UK dependent on pipeline and LNG imports. The country imports gas through the Langeled pipeline from Norway and via the Interconnector UK and BBL pipelines, which connect to the Netherlands and Belgium respectively. The UK also imports LNG and has taken two cargoes from Russia so far this year, in addition to deliveries from other suppliers.
The UK’s underinvestment in gas storage has been criticised not only because it has made the country more vulnerable but also because it reduces the flexibility to supply the continent through gas interconnectors. However, the UK has argued for many years that energy security is better served by diversifying supply rather than building storage – although a government select committee recommended in 2010 that the country should double its storage capacity from the 5 bcm that was then available.
The current winter/summer spread between prices at the NBP does not support the building of new storage facilities. A spread of 22-24 p/th would be required to fully support the construction of new capacity in underground salt caverns or depleted gas fields, but the spread is currently less than half that.
In its Winter Outlook for 2018, National Grid said the UK’s demand for gas this winter will be lower than it was last winter because of increased generation from renewables and greater use of coal in the power sector, which it predicts will be cheaper to burn than gas. The TSO predicted winter demand of 46.6 bcm and a 1-in-20-year chance that peak day demand will hit 472 million cubic metres.

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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