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.

On 1^st January 2021, the Brexit transition period will end and the UK will irrevocably cut any last remaining ties to the EU and head out to forge its own future, with or without a trade agreement in place. Many energy market participants may feel understandably uncertain about what this landmark political milestone will mean for their day-to-day business, particularly with the possibility of a last-minute deal still on the table. In this Insight, we pull together the various decisions and alternative arrangements that will come into effect from the start of 2021 to provide a clearer picture of what the energy market will look like.

Too late in the day (ahead)

The consensus from the various market operators is that even if there is an agreement made before the end of 2020, it is too late to update systems and implement the new deal before the transition period ends, except in the case that the EU agree to let GB participate in the energy markets exactly as they do now. Consequently, the GB zone will be decoupled from the European Internal Energy Market in January.

In practice, this means that the interconnectors serving GB will cease to use the Harmonised Allocation Rules and no longer be part of the Single Day Ahead Coupling [1]. In order for these interconnectors to still serve a purpose, alternative arrangements have been put in place.

Fig. 1. The expected market arrangements after the Brexit transition period (Taken from [1])

The Channel interconnectors (IFA, BritNed and NEMO) will now have capacity allocated via explicit capacity auctions [1] and will create a new set of Allocation Rules. Market participants successful in acquiring capacity in these auctions will be required to nominate that capacity or they will forfeit the right to use it, similar to the process that was previously ongoing in SEM through the Long Term and Intraday allocation timeframes. Another interconnector, IFA2, is currently commissioning and will be available for trading in the near future.

The Irish Sea interconnectors (Moyle and EWIC) will not be available in the SEM day-ahead market – effectively leaving the Irish market decoupled from Europe at this point. They will however be available in the Intraday 1 & 2 auctions, which will still couple the GB and Irish markets and allocate capacity on the two interconnectors implicitly [1]. All FTRs sold on the interconnectors will be reimbursed on the initial price paid for them, in accordance with Article 27 of the EU Guideline on Forward Capacity Allocation [2]. SEMO has indicated that no transmission rights products will be sold in the short-term until a new product offering is known [3].

Will the SEM markets Remain strong?

How the SEM markets change depends a lot on how market participants react to the new arrangements. The current expectation is that the magnitude and volatility of day-ahead prices will increase, and that there will be more liquidity in the intraday markets as they become the only markets in which Irish participants can exchange power with Britain. However, this assumes that British participants are as willing to trade in the comparatively smaller Irish market as their Irish counterparts. Equally, Irish participants might want to avoid uncertainty at intraday (which has seen much lower traded volumes than day-ahead since the beginning of ISEM) and may continue to trade primarily at day-ahead to secure their positions.

Not what we’re a-Customs-ed too

The lack of a trade agreement would also mean that declarations will need to be made on the import/export of goods between Ireland and GB. Westminster have stated that goods travelling from Northern Ireland to GB will not require declarations, but the EU insists that any goods imported to Ireland north or south and continental Europe will. In the case of power and gas flows, declarations will be made on behalf of market participants by the interconnector or pipeline operator [3], [5].

Better get EUsed to it

The new arrangements are likely to cause some disruption come January as participants find their feet in the new world, and this confusion combined with tight generating margin this winter [5] could lead to some unexpected market outcomes. In the long-run, inefficient interconnector flows will likely lead to larger wind curtailment levels during periods of high wind when Ireland would usually export, and more expensive wholesale electricity prices during traditional import periods as higher priced conventional power is called on in place of imports from GB, both of which could increase Ireland’s greenhouse gas emissions and make it more difficult to meet our 2030 targets.

A key consideration is that unless a last-minute deal allows GB to participate in the European energy markets exactly as it does now, these measures will come into effect in January 2021 – at best temporarily, until new arrangements struck under a deal can be implemented, or at worst permanently. Preparing now to manage these new risks and becoming familiar with the market changes will help your business make the transition to a post-Brexit world as seamless as possible.

Please contact our Client Services team at clientservices@electroroute.com if you would like to explore the hedging, trading, forecasting and balancing services that ElectroRoute can offer to manage new risks your business may face as a result of Brexit.

References:

[1] EPEX SPOT info, EPEX, 16^th October 2020

[2] COMMISSION REGULATION (EU) 2016/1719: Establishing a guideline on forward capacity allocation, 26^th September 2016

[3] Energy EU Exit Stakeholder Event, Department for the Economy, 11^th September 2020

[4] Nordpool announces GB Auction changes for Brexit, Nordpool, 19^th Oct 2020

[5] Market Operator User Group, SEMO, 8^th October 2020

The post (Inter)connecting the dots on future Brexit arrangements appeared first on ElectroRoute.

While today may be black Friday, there were no early deals last night (26^th November) for those doing their last-minute buying across the evening peak in the balancing market. At 14:00 an amber system alert was issued for Northern Ireland due to a generation shortfall. The alert was issued with an effective time of 16:00. Across the imbalance settlement periods of 17:00 and 17:30, the imbalance price reached €691.57/MWh and €658.06/MWh. This is above the €500/MWh strike price which holders of capacity market contracts are exposed to. The last time the strike price was reached was January 24^th, 2019. The alert was lifted at 19:00.

Why did this happen?

Generation shortfalls in Northern Ireland are not a new phenomenon.  There have been seven amber alerts since the start of I-SEM, five of which have been due to generation shortfalls in the north with three of those occurring this month. The EirGrid and SONI winter outlook for 2020/21 sounded the alarm bells early, with a predicted all-island capacity margin of only 929MW. The margin has been declining over the past five years as a result of;

• increasing outage rates of ageing plant
• dispatchable generation being replaced in the market by renewables, and
• a strengthening demand.

This year, the traditional summer outage season for generators was also disrupted by COVID-19 with the unavailability of specialist maintenance crews to travel from overseas. This created a knock on impact of large generators having outages during the winter months. One such outage relates to a 250MW Ballylumford CCGT unit located in Antrim. The EriGrid/SONI outlook forecasted that in Northern Ireland, if an outage of one large generator coincided with a period of low renewable generation there is a risk of a system alert.

So with anti-cyclonic conditions across the island yesterday, low levels of wind output (approximately 300MW across the island), temperatures hitting the low single digits and the outage of the Ballylumford plant, it was no surprise that an amber system alert was issued to the market. The GB power system was also experiencing tight margins. With the interconnectors coupled, day-ahead prices reached €336.2/MWh (the second highest day-ahead price since I-SEM began) at 17:00 with I-SEM due to export to GB. The export position at 17:00 persisted through the market coupled intraday auctions. This left the North in a precarious position as the Moyle interconnector, with lower losses than EWIC, is the first of the Irish interconnectors to be scheduled in the Euphemia price coupling algorithm.

As demand was on its way to reaching its highest level so far for 2020 (6.45 GW), several System Operator to System Operator (SO-SO) trades were executed to buy back the power that was to be exported. These system operator trades happened once the market has closed and facilitate changes to interconnector schedules to facilitate increased renewable generation or in this case, for reasons of system security. The price of purchasing power from GB across the 17:00-17:30 period was €924.66/MWh. With the Net Imbalance Volume (NIV) short, mostly driven by shortness on the demand side, the Moyle interconnector was the most expensive unit in the ranked set and remained unflagged throughout this period. Due to the price averaging in the imbalance price calculation (see our previous Insight on how imbalance prices are calculated here)  the settlement prices were lower than this value. The next most expensive unit was a Coolkeeragh peaker at €501.58/MWh. The last strike price event in January 2019 which was also driven by system tightness in Northern Ireland (see our Insight on this event here) ) resulted in a peak balancing price of €3,744/MWh but was set by Ballylumford peaking units with simple incremental offer prices of greater than €5,000/MWh. This is the first time that the imbalance price has been set at such a level by an interconnector.

Outlook

Even with the planned return of the Ballylumford CCGT for the start of December, there is the ever-present risk of unplanned outages occurring during similar climatic conditions throughout the winter months. If support is not available from GB during these times, we will likely see more of these high price events.

The generation shortfalls in Northern Ireland do show the importance of the North-South interconnector. The project, which will have a capacity of 1,500MW, received ministerial consent to approve planning permission in Northern Ireland in September 2020 having previously received approval in Ireland in December 2016. The current expected date for commissioning is sometime in 2023, still some time away.

Volatility

November 2020 has again highlighted the volatility of the Irish Market. In this month alone we have seen 41 periods of negative prices in the day-ahead market as well as the second highest day-ahead price. The balancing market has seen prices as low as €-243/MWh and yesterday’s high of €691.57/MWh. From a power system point of view, the need to be able to withstand peaks and troughs in both generation and demand is evident and there is only going to be an increasing requirement for a more flexible energy system. Naturally, there is a need for new and innovative trading products required to support the assets that will deliver such a system as we transition to a net zero carbon world.

Please contact our Client Services team if you would like to explore the trading, forecasting and balancing services that ElectroRoute can offer to support you in mitigating the impact of, or indeed maximising the opportunity from, this volatility on your assets.

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