by Peter21 | Sep 14, 2016 | Uncategorized
The article below appeared in the September 14th, 2016 edition of Natural Gas Daily, a specialist newsletter published by Interfax, focussed on the global natural gas and LNG industry.
The International Energy Agency (IEA) has said that the pace of global oil demand growth is dropping more quickly than initially predicted. In its latest monthly outlook, the agency lowered its forecast for oil demand growth in 2016 by 100,000 barrels per day, to 1.3 million b/d. It forecast the growth rate would be even lower in 2017, at 1.2 million b/d.
With OPEC producers pumping at close to record-high levels, the stock overhang that has stymied oil price rallies in recent months looks set to continue. Non-OPEC production has been dropping because of low prices, but not by enough to eat into bloated inventories. The IEA estimated that oil inventories in OECD countries hit a new record high in July, of 3.1 billion barrels, a rise of 32.5 million bbl from the previous month.
Oil prices rallied from four-month lows of around $41.50/bbl in early August to a high of $51.22/bbl on 19 August as peak summer demand for oil for transport kicked in. But the rally has faltered, and Brent futures currently stand at around $47.50/bbl. The northern hemisphere summer is usually a time when more oil is consumed – especially in the United States, where motorists guzzle nearly 10% of the oil used globally.
The IEA said OPEC crude production nudged higher in August, to 33.47 million b/d. This was 930,000 b/d above levels seen earlier in the year and was led by Middle East producers pumping at full throttle. The IEA said Kuwait and the United Arab Emirates hit their highest-ever output and Iraq also increased supplies.
Saudi Arabia and Iran have each raised their output by more than 1 million b/d since late 2014, when OPEC shifted its strategy to defend its market share rather than protecting prices. Saudi output has almost reached a historic peak while Iran has also reached a post-sanctions high. As Saudi Arabia had planned, the surge in its production has stolen market share from US shale producers. However, the slowdown in US shale production has been slower than expected as a result of lower costs and higher well productivity.
In its latest monthly report, which was issued on Monday, OPEC said that losses in non-OPEC supply would be less than expected in 2016, falling by 610,000 b/d rather than the 800,000 b/d decline it predicted earlier in the year. Additionally, it reported that non-OPEC production in 2017 would be 200,000 b/d higher than 2016 levels and that OPEC production of NGLs would rise by 150,000 b/d in 2017, to 6.43 million b/d. The OPEC report said third-party sources estimated its members pumped 33.24 million b/d in August, close to the recent production peaks.
The IEA’s own supply estimates are broadly similar to those of the oil cartel. The IEA expects non-OPEC supply to drop by 840,000 b/d this year, with high-cost producers hit particularly hard. However, growth will resume in 2017, with the IEA forecasting a 380,000 b/d year-on-year increase in oil production. Output gains are expected because North Sea fields that were shut for summer maintenance have now been brought back to full production, while Kazakhstan’s Kashagan field will also start producing again after extensive repairs. Eni has forecast production will recover to 360,000 b/d in 2017, above the level anticipated by the Kazakh government, the Financial Times reported.
“Supply will continue to outpace demand at least through the first half of next year,” the IEA said. “Global inventories will continue to grow […] As for the markets’ return to balance – it looks like we may have to wait a while longer.”
by Peter21 | Sep 7, 2016 | Uncategorized
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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