It’s been an amazing journey over the past 13 years.  While the pendulum of my focus must now swing to family and my personal life, I will forever be very proud of what has been achieved in ElectroRoute.

Saying goodbye is bittersweet, but it does afford an opportunity to acknowledge successes to date and wish everyone the best for the exciting chapters ahead.

Over the past couple of weeks, I’ve found myself reflecting a lot on the extraordinary challenges and achievements along the path of building ElectroRoute, from literally a set of ideas discussed for hours over kitchen and barroom tables in 2010 to what we have today.

The current range of activity of our pan-European trading company is wonderful.  A full end-to-end trading platform capable of scheduling electricity in a matter of minutes to trading natural gas many years ahead.  We’re shipping Biomethane through pipelines right across Europe one hand and underwriting the risks facing renewable assets for the next decade so that they can be financed on the other.  Since inception ElectroRoute as a company has been intent on knitting together the complicated threads of a decarbonised energy system.

I’m enormously grateful to Alex Bryson, Eamonn O’Donoghue, Alan Mullane, and Bernie Fitzpatrick – the steely co-founders who never wavered along the journey. Their fundamental belief in the mission of building a decarbonised energy system and the commercial opportunity that lay therein bound and fuelled the management team over the years.

While I’m stepping back myself at this juncture, ElectroRoute’s next phase is looking even brighter. Under the leadership of our new Co-CEOs Caoimhe Giblin and Donal Flynn, the company will benefit from vast experience and an expansive professional tool kit.  Two brains will certainly be better than one as the company drives confidently ahead.  I have always felt very privileged and humbled to count Caoimhe, Donal, and our HR director Catherine Kelly (all my professional seniors previously in Airtricity) as part of my team in ElectroRoute.

I have to suppress the temptation to elaborate endlessly in praise of the fantastic staff I have had the pleasure to work with, the friendly and open company culture we created and the innovative approach to technology at ElectroRoute. There simply aren’t enough words or time to do justice to the incredible people who have walked through our doors.  It’s been a great privilege working with each and every one of you across all locations, whether in Dublin, London, Tokyo, or of course, Donegal.

Great credit goes to our early-stage investors, central to whom were Paul Dowling and Bran Keogh. They helped us get on, and stay on, the right path. Over the past 7 years joining the Mitsubishi Group of companies has been instrumental in propelling ElectroRoute to its current significant European and indeed global footprint.  The scale, strength, and quality of our business today is testament to the invaluable collaboration and strength within the Mitsubishi family. That we now have a full suite physical and financial power trading platform operational and staffed in Tokyo is evidence of the potential for our collaborations in the years ahead.

The future is bright.  While I’ll be doing different things in the future, I am very excited to watch ElectroRoute continue to evolve and thrive under its new leadership. To everyone who has been part of this remarkable journey, thank you for making the last 13 years truly unforgettable.

Ronan

The post A Word of Thanks appeared first on ElectroRoute.

23^rd September 2021:  ElectroRoute the leading Irish energy trading and services firm has today announced its first major contract in its expansion into the giant Japanese energy market with a milestone corporate Power Purchase Agreement (PPA) between its sister company MC Retail Energy and a corporate buyer.

ElectroRoute’s IT systems and expertise will hedge the balancing cost for MCRE and ensure the viability of the project.  ElectroRoute today predicted that this would be the first of several agreements as Japan races to meet challenging 2030 and 2050 renewable energy targets.

Commenting on the deal ElectroRoute CEO and Co-Founder Ronan Doherty said, “Japan is the world’s third largest economy and has a particularly interesting energy market in that it deregulated significantly later than Europe. All told the demand is 34 times that of Ireland for example, and Japan is investing heavily in renewables which requires international expertise like that which we have deployed over the last decade to enable it reach highly ambitious climate commitments.  We were delighted to support MCRE on this landmark corporate PPA.”

ElectroRoute signalled its intent in the Japanese market in late 2020 with Founding Director Eamonn O’Donoghue relocating to Tokyo. The company will leverage its ElectroRoute CORE IT platform based in Dublin, which uses deterministic and machine learning forecasts for solar sites to manage the balancing risk for the portfolio in the Japanese power market.  The portfolio will be managed by ElectroRoute’s 24/7 trading team which also currently manages the trading and balancing for 600MW of wind assets in the Irish market.  ElectroRoute currently provides trading services for a total of 1.4GW of energy assets.

Head of Japan Power Trading & Marketing and Director of Trading Eamonn O’Donoghue said the country had seen phenomenal change over the last decade due to ongoing deregulation and the challenges posed by the Fukushima nuclear disaster in 2011.  “The country is already a world leader in solar infrastructure but this is the first time corporates are properly investing as the race is on to maximise all available renewable opportunities.  We are anticipating a significant expansion of solar corporate investment as well as wind and our bespoke offering is exactly what our client base is telling us they require”.

Contacts:

 Eamonn O’Donoghue, Head of Japan Power Trading & Marketing and Director of Trading – e-mail: eamonn.odonoghue@electroroute.com

Caoimhe Giblin, Commercial Director at ElectroRoute – e-mail: caoimhe.giblin@electroroute.com

Aidan Power, Japan Business Associate at ElectroRoute – Tel: +353 1 556 3097 / e-mail:

aidan.power@electroroute.com

The post ELECTROROUTE SIGNS LANDMARK SOLAR BALANCING DEAL IN JAPAN appeared first on ElectroRoute.

Following a successful innaugural Energy Storage Ireland Conference this week, our latest Insight builds upon the theme of our presentation at the conference by Brian Kennedy, Head of Trading Solutions at ElectroRoute. Specifically, we examine the nature of transition in revenue for energy storage assets on the island of Ireland.

Revenue Model Evolution

Traditionally, energy storage projects have focused on the 3 standard revenue streams, being;

i)   system service revenue,

ii)  capacity market revenue, and

iii)  energy market revenue.

We have seen that the contribution of revenues today is strongly weighted towards system services, with DS3 revenue making up a significant percentage of the overall pot of revenue for a battery system.

The recent announcements of a review of the DS3 tariffs has led to an understandable focus around what the future looks like and how revenues will be weighted going forward. Taking account of our experience in other markets, we see that whilst competition may lead to an overall reduction in ancillary services revenue, more focus should be given to the nature of the transition and opportunity in other areas.

It is likely that as a result of the rapid evolution of the power sector, the value drivers for storage will continue to be transient and likely move in shorter windows between energy arbitrage to ancillary services and from one system service to another.

Figure 1: Energy Storage Revenue Diversification

Staying Ahead of Change

It is understood at the moment that the ancillary services regime will move to a competitive procurement model from around 2024, however it is important to recognise this milestone as the starting point in the transition. From this point, competition and liquidity will drive new revenue dynamics for all participants, and the renewable integration on the system is likely to result in the implementation of new or tweaked services which respond to the system challenges presented as a result.

It remains imperative therefore that storage assets being designed today are done so in a manner which allows the unit to take advantage of new revenue opportunities as they arise.

Specifically, this means batteries that can cycle regularly and have adequate storage duration to respond to reserve/wholesale market opportunities.

This is equally true of the trading strategies which should be future proofed to ensure a seamless transition to capture new revenue opportunities.

New Revenue Opportunities

An area of focus for ElectroRoute is also around the opportunity to find new revenue opportunities for storage assets. It is likely that such opportunities, be they demand firming, portfolio management or supporting carbon accounting agendas, will be characterised by low liquidity and accessed by bilateral contracting rather than by tradition registrations to a marketplace. We refer to these as extrinsic revenues and assume their access will be driven by trading houses primarily.

The challenge for the storage sector and trading businesses such as ElectroRoute is to monetise such revenues whilst also mitigating the likelihood of a lower level of certainty to the revenue model.

The illustrative example below in figure 2 shows interlinking of revenues with extrinsic value with intrinsic revenues (capacity, energy, ancillary services) for a potential optimisation of revenues.

Figure 2: Energy Storage Revenue Optimisation

It is important to note that the optimisation approach to energy storage business models is not without risk, and the movement of value across different services and markets means investor returns may no longer be underpinned by stable regulatory tariffs. The movement away from revenue certainty results in a greater focus on the trading house, such as ElectroRoute, to warehouse these risks and provide bespoke solutions to battery asset owners which provide some level of security and certainty.

Figure 3: Volatility in revenue capture

The nature of this risk potentially opens a requirement for trading entities to provide tolling style agreements, that offer energy storage assets a fixed price in return for high availability.

If you would like to speak to ElectroRoute regarding our Trading Solutions for energy storage projects in Ireland, please contact brian.kennedy@electroroute.com

The post The Evolution of Energy Storage Trading Strategies appeared first on ElectroRoute.

This market insight looks at the key trends and figures in I-SEM in 2020.

Generation Mix

As in previous years, natural gas fired generation led the way in power generation in 2020. An additional 5% of the generation mix was delivered by Wind units in 2020 over the previous year as it continued to increase its share. This contributed to I-SEM being a net exporter of power over the year. The limitation on exports over the Moyle interconnector was increased from 80MW to 250MW in December opening up the opportunity for wind to increase its output into the system.

The contribution from the coal units at Kilroot and Moneypoint was marginally higher than in 2019, while peat fired generation had a reduced presence in the mix. Generation at West Offaly and Lough Ree peat units was limited over the summer months due to environmental restrictions, and the two units closed permanently in December, removing 235 MW of dispatchable generation from the system.

Several operational constraints were introduced during the year to counter the impact of COVID-19 on the maintenance schedules of thermal units. These constraints on Dublin Bay, Huntstown 2 and two Ballylumford units managed the run hours of these units to reduce risks for margins across the 2020/21 winter period.

On several occasions in the second half of the year, the system operators on the island issued Amber Alerts, indicating tight generation margins, specifically that the loss of a large generation unit could result in the inability to meet demand. In previous years these alerts had been issued for Northern Ireland only, however many of the alerts in 2020 were for both jurisdictions.

Figure 1: Generation Fuel Mix in 2020

Wind Performance

Wind generation started the year very strongly with a capacity factor of about 40% in Q1 and a new Irish wind output record of 4,259 MW was set in February. Overall, for 2020, the capacity factor for wind was approximately 28%. The volumes of wind generation dispatched down were considerable throughout the year. This wind, which was available but couldn’t be accommodated on the system due to local constraints and system wide curtailment, amounted to 12% of available wind generation. This was a marked increase on the previous year’s 8%. The driver of the increase in dispatch down volumes was largely due to high wind capacity factors and lower demand.

Figure 2: Wind: Outturn Generation, Dispatch Down and Capacity Factor

The system operators are continuously pushing the boundaries in how they operate the system and continued this in 2020, to allow greater volumes of wind and solar on the system. Two notable developments in this area were (i) the increased SNSP limit trial, which saw the system operators allow up to 70% of generation on the system to come from non-synchronous resources (a longer trial of this limit is currently ongoing), and (ii) an easing of the 400kV constraint group so that only in scenarios where system wind is below 1GW is a unit under this constraint group required to be running. The increased export capacity over the Moyle interconnector and the reduced minimum generation level of Coolkeeragh CCGT unit also facilitates further wind and solar on the system.

The following table shows the relationship between wind generation and market prices. It shows the average day ahead market (DAM) price and the average balancing market (BM) price on the 10 highest and 10 lowest wind generation days. As expected, the volume of available wind has a significant impact on the DAM price.

Table 1: Market Prices on the 10 highest and 10 lowest wind generation days

Demand

The graph below shows the average all-island daily demand per month in 2018, 2019 and 2020. The start of the year saw a strong demand for power, followed by a sharp drop from late March following the introduction COVID-19 related lockdown measures. These measures continued to deflate system demand until the middle of June when the lockdown measures were eased, and the economy started to reopen. The effects of lockdown were seen again from late October for several weeks when the Irish government introduced level 5 restrictions. Demand bounced back strongly in December following the temporary easing of some lockdown measures.

Figure 3: Average Daily Demand per Month in 2018, 2019 and 2020

Commodity and I-SEM Power Prices

The graph below shows the average DAM prices for 2019 and 2020, and the daily averages. There was a considerable drop in the average DAM price in 2020 compared to 2019 due to a combination of lower demand and lower commodity prices. In terms of DAM prices, the highest price reached €378/MWh while the lowest was €-41/MWh, which was one of a total of 381 hours in which the DAM price was negative. Another first in 2020, was a negative baseload price (average price) in DAM which occurred on April 5^th and reoccurred on a further 3 days, all of which were during the first COVID-19 related lockdown.

Figure 4: Average Day Ahead Market Prices in 2019 and 2020

The large volatility in the balancing market (BM) saw prices range from €-390/MWh to €691/MWh. That high price, which breached the capacity market’s reliability option strike price, occurred on a day when an amber alert was issued – check out this insight for more information on that event. The imbalance price was negative for a total of 1099 settlement periods (30 min periods).

Figure 5: Day Ahead Market and Balancing Market Prices in 2020

On the commodities front the impact of COVID-19 is also evident, particularly on gas and carbon which are key drivers of the DAM price. Coal has been relatively flat throughout the year. Carbon fell considerably as lockdown measures were introduced throughout the EU in March but recovered steadily and closed the year strongly by reaching an all-time high above €31 a tonne in December.

Figure 6: Carbon, Coal and Gas prices in 2020

The start of 2020 saw gas prices continue to fall due to strong supplies with increased availability of LNG, a warmer than average winter 2019/20 and demand reductions caused by the economic impacts of COVID-19. In May, European gas markets traded at all-time lows and the UK’s NBP day-ahead contract traded as low as 6.5 p/th, more than 30 p/th lower than the 5-year average for this time of year. The year ended with gas prices finishing strongly with cold weather forecasts and a tight LNG market driven by strong Asian demand. This insight delves into the dynamics of LNG in 2020.

Figure 7: Average NBP Gas Prices in 2020

Outlook

Already in the first few weeks of 2021, I-SEM has delivered several new records, with a new DAM price record and wind generation levels passing the record set in February 2020. One significant point is the impact of Brexit on I-SEM – in this insight we summarise the first month post Brexit. A cold weather spell combined with thermal units on forced outages have led to tight system margins. High volatility in gas and carbon prices have continued into 2021.

Please contact our Client Services team if you would like to explore the trading, forecasting and balancing services that ElectroRoute can offer to allow you to mitigate the risks or maximise the opportunities of your assets.

The post I-SEM in 2020 appeared first on ElectroRoute.

As the first month of the post Brexit trading arrangements has come to an end, it is time to look back and see how I-SEM has been affected.

What happened?

On January 1st at the end of the Brexit Transition period the GB market decoupled from the European Internal Energy Market (IEM). The lead up to this has been covered in a previous blog here. (https://electroroute.com/interconnecting-the-dots-on-future-brexit-arrangements/).

The channel interconnectors IFA (2,000 MW), IFA2 (1,000 MW), BritNed (1,000 MW) and NemoLink (1,000 MW) now have their capacity allocated via explicit daily auctions rather than the implicit auctions that are used as part of the Euphemia Price coupling mechanism. As Ireland was connected to Europe through our interconnection with GB we also decoupled from the IEM. Ireland and GB moved to local day ahead power auctions with the full capacity of Moyle (500 MW) and EWIC (500 MW) available to be allocated implicitly in the SEM-GB coupled auctions IDA1 and IDA2.

How did the GB and I-SEM Markets react to all this change?

January has been overshadowed by periods of low generating margins in GB and Ireland and the high prices that followed these. The imbalance price in GB reached £4,000/MWh on Friday 8th of January. The I-SEM imbalance price reached a high of €1,720/MWh for two periods on Tuesday 12th of January.

Were these high prices a result of the change to the markets? Or would they have happened anyway?

January saw high demand in GB due to colder temperatures, unavailability of some gas and nuclear plants and low renewable output due to the calm weather. This, along with the reduction in coal generation over the last number of years in the UK led to very tight generation margins and market notices, such as the below, being published.

If generation margins on the Irish system are tight during these times and if the interconnectors are due to export over the evening peak, then EirGrid may be required to reduce or even reverse the flows of the interconnectors. This will come at high cost through a series of SO-SO trades with National Grid.  So, the high imbalance prices are not necessarily a result of the new trading arrangements. The auction prices are a different story…

While the new arrangements do not guarantee higher auction prices, they have led to a greater price divergence between the UK day ahead market and the Continental markets.

BritNed has been on an outage and is not due back until early February. IFA2 (1,000 MW) was only commissioned on 24th of January. So that left only Nemo Link and IFA flowing power into GB for most of the month. With low generating margins forecast over hours of peak demand, this was only going to send GB day ahead prices one way, upwards! As Ireland experiences similar weather conditions to GB and had a number of significant outages over the month I-SEM Day ahead prices also followed suit. But what about the intraday auctions… In December we posed some questions on how the I-SEM market, particularly the intraday auctions, would be affected. These are addressed below.

Have intraday traded volumes increased?

The below chart shows the IDA1 and IDA2 average traded volume per month since January 2020 as well as the average baseload auction price for each month. There is a clear step change in volumes traded in IDA1 since the start of January. IDA2 has not seen as significant an increase in volumes. This is likely because the buying demand was coming from GB and all the room on the interconnectors was taken up in IDA1. The increase in the baseload prices is due to an increase in gas prices and GB buyers willing to pay a premium to the I-SEM Day ahead price.

Has the volatility between I-SEM DA and IDA1 increased?

The below chart shows the spread between DA and IDA1 prices for the hours of peak demand (17:00-19:00) for each day of November, December, and January. Greater than zero means that the IDA1 price cleared higher than the DA price.

The volatility has increased significantly on tight margin days due to the magnitude of the GB day ahead price and GB balancing prices. On days where generating margins are not an issue the volatility is not as high. More data will be required to see whether this relationship holds over the long term.

Will there be enough GB participants willing to trade in IDA1 and IDA2?

So far it seems as though there are enough GB participants willing to trade in IDA1 as GB traders look to take advantage of lower prices compared to the GB day ahead price. The issue may be that there could be too many I-SEM sellers in IDA1 and IDA2 under certain conditions.

Taking January 15th for example, wind was forecast to ramp up in Ireland across the day, while the wind in GB was forecast to remain low. The GB Day Ahead price cleared at an eye watering £1253/MWh for the peak hour, while the I-SEM Day Ahead price cleared at €130.97/MWh on the peak. I-SEM traders looked to IDA1 as an opportunity to sell at a better price. As the chart below shows, this worked out for the day off peak hours, but it backfired over the evening peak with IDA1 prices dropping relative to DA as too many sellers tried to clear their volume.

Conclusion

Tight winter margins are here to stay particularly during periods of cold weather, plant outages, and low renewable generation. The unavailability of the interconnectors in the day ahead auctions in GB and I-SEM will continue to affect Day Ahead prices particularly on low margin days. This will also increase the volatility between Day Ahead and IDA1 prices. However, if too many participants try to take advantage of this it will likely work against them as there is only so much room on the Irish Sea interconnectors.

If the GB and I-SEM markets had remained in the Internal Energy Market this would have provided downwards pressure on the GB Day Ahead prices in January and less volume being traded in IDA1 along with less volatility. The interconnectors going explicit has been good for dispatchable generators but will cause some pain for suppliers due to higher power prices. More data will be required to fully assess the impact of the post-Brexit trading arrangements over the long term.

For intermittent generators who also have to worry about forecast errors these price spreads on tight days can cause a headache. Some form of price coupling is due in April 2022 [1]. However, the timeline for getting this done seems ambitious.

Please contact our Client Services team if you would like to explore the trading services ElectroRoute can offer to allow you to mitigate the risks or maximise the opportunity of these new market conditions.

[1] https://ec.europa.eu/info/sites/info/files/draft_eu-uk_trade_and_cooperation_agreement.pdf

The post Life after Brexit appeared first on ElectroRoute.

Last year was a year like no other and while most will think of the world-wide pandemic or the Australian bush fires, those in energy circles will not forget the LNG market of 2020. A tale of two halves, the market moved from buyers cancelling LNG deliveries due to large oversupply, to LNG shipments being a worldwide scarcity.  But what were the drivers behind the large shift? And where did it all begin? 

Winter 2019 was mild and one of the warmest of both Europe and Asia in recent times. As Q1 2020 continued, the now infamous Covid-19 virus struck China, the second largest LNG demand hub in the world behind Japan, and left utilities throughout the country with an oversupply of the commodity due to Covid-19 related demand destruction and warm weather.  CNOOC, the largest importer of LNG in China, declared Force Majeure and refused to accept cargoes from across the globe due to concerns over the spread of the virus. While some suppliers such as Total SA rejected the Force Majeure, it set precedent for several of the world’s largest importers to follow suit with India declaring Force Majeure not long after. LNG tankers en-route to China were diverted while others idled offshore. Covid-19 was the final straw for tumbling global gas markets which had struggled to find support due to the warm Winter and plentiful supply.  

Come the Summer months, forward contracts in Europe were falling towards the 10€/MWh mark. US crude oil (WTI) made global headlines as the May contract turned negative on expiry due to storages hitting tank tops and traders closing their physical positions. US upstream shut-ins became inevitable. One by one, rigs across the US closed and production came to a standstill. In March 2020, the Baker Hughes drill-rig count showed 682 rigs in production. Come June that number fell to 172, a drop of 75%.  This had a colossal influence on the US gas market due to the large amount of associated gas produced in US oil rigs. As US gas rallied and European and Asian markets continued to fall, US LNG suppliers felt the pinch as arbitrages closed and LNG exports became unprofitable. This trend continued throughout the Summer and cancelled shipments from the US became a common occurrence with up to 45 cargoes a month being declined.  

August was the start of a shift towards what would be a Winter of volatility across global energy markets on the back of what was happening in the LNG sphere. Hurricane season in the US Gulf Coast came with furor and was making records for the number and intensity of storms which would hit. Hurricane Laura and Marco amongst others would be the most notable and lead to shut downs and damage to three of the largest LNG liquefaction facilities in the world; Sabine Pass, Corpus Christi and Cameron. Sabine Pass, the largest of the plants, which has the capacity to export up to 8 cargoes a week was brought to 0 from the 24th of August to the 10th of September after the damage caused by Hurricane Laura. This led to a backlog of vessels waiting to load LNG from the plant. This backlog was further exacerbated by none other than a sunken barge blocking one of the major access routes, the Calcasieu Ship Channel, for several days across September. 

As September came to an end, the rate of vessels departing the Gulf loaded with LNG was increasing as production and infrastructure problems were solved. Delayed shipments were arriving to the Panama Canal simultaneously which led to the beginning of one of the main causes of sky-high Winter prices, the congestion of the Panama Canal.  

 The Panama Canal marks the main shipping route from the US to Asia and is by far the most cost-effective path. In an emailed statement, the Panama Canal Authority assigned the congestion to “a combination of higher-than-average arrivals, seasonal fog and added Covid-19 safety procedures”.  Come the end of October the waiting time for vessels to enter the Panama Canal was reaching as much as 10 – 14 days. For reference, a typical trip from the US Gulf Coast to Tokyo, Japan would take 21 days. Trips were now taking a month, and that was only one-way. Shippers now began to send cargoes East from the US, around the Cape of Good Hope in Africa, and toward Asia to try and exploit the ever-growing Asian price.  

The effect of the Panama Canal congestion could not be understated as vessels being tied up in 2-month round-trips led to record chartering rates. As October approached, demand recovery in Asian hubs was becoming evident. China had the quickest growing economy in the world and their LNG demand reflected this.

Asian premium over other world markets began to grow but it would now need to price in increasing chartering rates, longer travel times and competition from other Asian buyers. 

Fig 1 – A stream of LNG cargoes leave the US for Asia transiting the Panama Canal (Source; Kpler) 

Whilst LNG demand recovery became clear, LNG supply was not on the same trajectory. Indonesia, Malaysia and Trinidad and Tobago amongst others all faced unplanned outages and production problems while a fire at the Hammerfest LNG plant in Norway meant a 12-month full shutdown.

In a final addition to what would be the perfect storm, Qatar, the largest LNG producer in the world, also faced production problems just as Winter demand came to fruition.                                          Qatar also chose not to sub-let any of its’ spare LNG fleet, putting further upward pressure on shipping prices.  

As the depths of Winter approached, the cold weather struck. Power market dynamics in Asia added to the increasing demand as South Korea decommissioned coal plants and Japan saw several nuclear plant outages. The number of LNG shipments travelling from the US to Asia by the Cape of Good Hope in November and December doubled year-on-year and the increased travel time led to further incremental bookings of spot shipping capacity with some reports stating that shippers were simply unable to secure any capacity in the tight market. 

Towards the end of 2020, JKM disconnected from any fundamental markers. While freight and shipping rates had been setting the JKM price, spot prices for LNG were now escalating past any form of marginal costs related to increased freight rates. Driven by supply outages and scarce shipping availability the market struggled to find any form of price anchor and buyers were now willing to pay over 30$/MMBtu for spot tenders delivering in January.  

 Fig 2 – JKM (Asian LNG marker) forward contract price; 01/01/20 – 31/12/20 

The tightness in the LNG and shipping markets would lead to blowouts in several world energy markets across the globe from Japanese power which hit a baseload daily price of 154.57JPY/kWh (1236.56 €/MWh) and Spanish gas which hit 50 €/MWh for Day-Ahead delivery this January. It showed the integral role LNG now plays in not only worldwide gas hubs but power markets alike, in what is likely to be a long-standing relationship for the foreseeable future.  

ElectroRoute actively trades on the main European Gas Hubs, including physical trading, and encompass a wide spectrum of activities supported by our internal trading platform which covers an end to end trading process for our clients. ElectroRoute can provide its clients with a range of route-to-market solutions which allows for different levels of revenue certainty, revenue potential and operational discretion.  

For more information please contact clientservices@electroroute.com if you would like to explore this further.  

The post 2020 in LNG – A tale of two halves appeared first on ElectroRoute.