In 2022, we have witnessed unprecedented challenges in the energy market. The current state of energy security in Ireland is heavily reliant on imports and an ageing gas fuelled power sector. Ireland has now developed a plan for both the near-term and long-term outlook which looks at our Oil Security, Natural Gas Security and Energy Security particularly due to the tightening of global gas markets exacerbated by the Russian invasion of Ukraine.

Ireland’s Energy System

– a quick overview

Ireland imports over 70% of its total energy requirements, in the form of heating, transport and power generation. This is higher than the EU, which imports nearly 60% of its total energy use needs.

Oil and natural gas represent about 80% of Ireland’s primary energy requirements.

The Governments Climate Action Plan 2021 sets out to increase the share of electricity consumption coming from renewables to 80%, as well as enhanced energy efficiency within the transport and residential sectors. In 2020, renewables accounted for 42.5% of the gross final electricity consumption.

1. Oil Security

The National Oil Reserve Agency (NORA) maintains 90 days of strategic oil reserves, stored in oil storage facilities in Ireland, the UK and EU member states with whom Ireland has a Bi-lateral Oil Stockholding Agreement.

Currently, NORA holds c.72% of its total oil stocks in Ireland and the remaining balance abroad. This reserve is spread across various products, including petrol, diesel, gas oil, kerosene and jet fuel.

Stocks are currently held in oil storage facilities in Dublin, Cork (Whitegate Refinery), Whiddy Island, Foynes, Shannon, Tarbert, Galway, Derry and Kilroot. European stocks are held in Denmark, Sweden and Spain.

In Figure 2 it can be seen that the number of days of oil stocks kept by NORA has been greater than the required number of days to be held.

As Ireland has no domestic oil production all reserves need to be imported:

• One-third of the imported oil is crude oil which is refined into oil products at the Whitegate refinery.
• The remaining two-thirds are imported as refined products.

Irish crude oil imports are sourced from Norway, Denmark, the US, the UK and OPEC member countries. Refined products are sourced from the UK, the US, Sweden, the Netherlands, Norway, Belgium and previously Russia.

The commercial oil sector in Ireland operates on a just-in-time basis, with relatively limited supplies held by suppliers at any one time.

2. Natural Gas Security

Irish natural gas supply depends on imports from a single source, the Moffat interconnection point between Ireland and Scotland. The Corrib Gas Field, Ireland’s only indigenous source of natural gas, is set to decline over the next 10 years. This coming winter (2022/23) Corrib is anticipated to meet 21% of ROI natural gas demand, and 16% of the island’s total demand, Moffat will supply the rest. In winter 2021/22 Corrib met 28% of the Republic of Ireland’s natural gas demand.

High dependence on imports from the UK, along with the reliance of the electricity system on natural gas supplies, means that Irelands needs to urgently diversify its gas supply options and explore the development of Liquified Natural Gas (LNG) facilities on the island. While there are lingering concerns regarding LNG, it does present Ireland with the least-worst option to manage security of supply during the period of the transition to 100% renewables.

3. Electricity Security

Natural gas is used to generate around 50% of Ireland’s electricity, therefore, any impacts on the natural gas supply will affect the electricity Security of Supply. The other 50% is generated by a mix of renewables, coal, oil and waste-to-energy, with renewables increasingly becoming a larger proportion of the mix in recent years.

All large gas-fired power stations are required to have secondary fuel capacity along with oil stocks that would allow them to operate for 3-5 days without natural gas, in case of an interruption to natural gas supplies.

Moneypoint, the largest coal-burning plant on the Island is operated by the ESB, which is identifying alternative sources for future coal deliveries in the context of the EU’s ban on importing coal from Russia. Since the ban, the majority of Irish coal imports have come from Colombia or Poland.

4. Electricity Emergency Management

When the potential loss of a single generator/interconnector could lead to insufficient electricity generation to meet demand, an Emergency State will occur. This occurs when there is a high risk of failure in meeting system demand or when operational limits are violated. During this Emergency State, EirGrid may have to reduce or cut off supplies of electricity to some consumers, this includes a mandatory demand curtailment process which reduces the demand of large energy consumers, including those who operate with backup generators.

2022 Winter Lookahead

The anticipated peak demand for the coming winter period is between 5456MW and 5786MW, this would exceed the previous record set on 8th of December 2021 of 5391MW.

De-rating factors are applied to the generation capacity of Ireland’s available generating units, this reflects the contribution of each generator to capacity adequacy. The de-rating factor for a conventional dispatchable generating unit is generally based on forced outage rates in a rolling three-year period.

The de-rated margin is the sum of the de-rated generation capacity from all available generating units and interconnectors, less the forecast demand and reserve requirements. A positive de-rated margin means there is a greater likelihood that we will have sufficient capacity to meet demand, while a negative margin indicates a shortage in generation capacity.

EirGrid has stated a de-rated margin of -9MW for the coming winter period which indicates that the system is very tight this winter and there is a risk of a shortage of power.

Long-Term Considerations for the Future of Energy Security of Supply

EirGrid’s Generation Capacity Statement considers the balances between electricity demand and supply during the years 2021-2030. There are plans for newer, cleaner gas-fired plants to replace ageing plants being retired due to the transition to low-carbon and renewable energy.

The statement concludes that:

• The electricity industry will have to find new ways to meet the increasing need for energy without relying mainly on burning fossil fuels.
• New government policies are expected to help guide us away from fossil fuels toward alternative heating methods, such as electric heat pumps, and cleaner modes of transport, such as electric vehicles.
• This changing demand and generation supply landscape for the island will require coordinated management of both the volume and type of new capacity, alongside new ways of managing increasing demand to ensure the security of supply.
• To prepare for this change, EirGrid must make the electricity grid stronger and more flexible. Given the scale of change, there is a need to plan for a lot of new grid infrastructures – such as underground cables, pylons and substations.
• The Irish electricity ecosystem supported by EirGrid is at the vanguard of delivering a cleaner, affordable and secure supply of electricity for consumers in both jurisdictions. Mapping the island’s electricity needs is an important feature of our work; it helps our governments, regulators and industry to prepare for the future.

In short…..

Generation deficits are set to increase in the short term due to the deteriorating availability of power plants, with EirGrid’s winter lookahead stating a de-rated margin of -9MW, which is indicative of a shortage of generation capacity in times of crisis. However, looking past this winter, the generation deficit is expected to reduce in the long term, as new generation capacity is added, and the grid enhanced.

Long-term structural changes need to be made to meet the forecasted rise in electricity demand. With plans to increase the percentage of renewables in the mix for the long term, the increased indigenous production will reduce Ireland’s reliance on imports, and further bolster energy security on the island.

Article written by Jack Atkinson

If you would like to speak to ElectroRoute about our services, please email us at info@electroroute.com 

About ElectroRoute….

ElectroRoute, a subsidiary of Mitsubishi Corporation, is a renewable-focused energy trading company, offering our services in Europe and Japan.  For more information on our services, click this link.

The post Energy Security for Ireland: This Winter and Beyond 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.

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.

The post Amber Thursday appeared first on ElectroRoute.

In the first of our series of Insights revolving around the battery storage sector on the island of Ireland, we explored the market for batteries at present. The DS3 arrangements are the focus for revenue capture at the moment for battery sites given the attractive DS3 regulated tariffs and reasonably low barrier to entry. However, we noted a point of caution; DS3 is not providing long term certainty and beyond April 2023, if not before, the market opportunities become more opaque.

In this Insight, we explore how the likely future reduction in DS3 rates will lead project sponsors to shift their risk appetite towards energy markets. An integral piece of this shift in business model will be design capabilities of the battery.

DS3 – Here today, but what of tomorrow?

We know that DS3 regulated tariffs are reasonably secure until around 2023, assuming that the tariffs are not reduced before. The maximum allowable budget for DS3 is €235mln per annum. Where this budget looks likely to be breached, or where EirGrid have procured more services than required, the regulated rates can be re-evaluated downward prior to 2023.

Beyond 2023, the DS3 contracts allow for two extensions of 18 months where deemed required by EirGrid. In the recent SEM Committee Scoping Paper on the future of system services, the following is stated;

“There is scope to extend the current contracts by two periods of 18 months. The RAs [Regulatory Authorities] may exercise this option should any issues arise which delay the implementation of a new framework”.

We expect the extension of these contracts to be subject to approval depending on the state of succeeding services programmes.

If we look to our neighbouring markets, we see that there is a likelihood for revenue markets to move and ebb and flow constantly. In Great Britain, we’ll soon see the movement away from Firm Frequency response to new products. In Germany and surrounding markets, the Operating Reserve markets have undergone market changes, now trending to shorter duration auction windows. At home, the SEM Committee have already initiated a scoping exercise on the future system services arrangements. It is clear therefore that keeping a project positioned in numerous revenue markets to stay ahead of this dynamic situation is of paramount importance.

Regulatory policy drives near term battery design

We’ve recently seen the CRU recognise the need to abolish double charging for network usage for battery technology. This raises the question; is a battery considered generation, supply or neither? It’s not a simple answer and hence the CRU have implemented an Interim Solution on Network Charging whilst the area is considered and a path forward developed.

The interim solution is to charge for network usage on the basis of Demand TUoS. This has the effect of incentivising asymmetric connections to the power system. In other words, batteries will look to reduce their Maximum Import Capacity whilst maximising Maximum Export Capacity. The battery can then optimise its DS3 provision and minimise its operating costs via reduced network charges. This makes sense today. However, as we’ve noted above, DS3 revenues are not set in stone for the lifetime of a battery installation, so this solution has the impact of slowing the rate of charge to replenish battery stores on the island.

In a world where arbitrage and system balancing becomes an important revenue possibility and system tool, how does this impact the potential for the battery installation?

We can see in the figure below, a battery installation with a MIC:MEC of 1:5. We can see the time taken to charge after a full discharge is therefore almost linearly extended.  Given that the unit requires this long to charge, it is highly unlikely the unit can avail of spreads within the daytime hours.

Consider this situation in an arbitrage model. The project is effectively limited to one cycle a day.

Were the unit to have a symmetric MIC:MEC, the opportunity for the battery to react more readily to system conditions is clearly apparent. This is highlighted in the graphic below. Note that these are highly illustrative examples and not considering other factors such as warranty limitations on cycling.

Not only do we consider the charge rate when assessing the capability of a battery to support system balancing, the duration of the battery is a clearly important metric.

The vast majority of batteries under development are in the range of 25-35minutes of useful life at full discharge. Again, the capability of a battery to contribute to an extended event, such as a major plant outage or a low wind period, is somewhat limited where the battery is constrained to such durations. We see the market developing towards 2-hour plus durations, however this is largely driven by the cell costs of batteries, and equally the assurance that the market signals such as negative pricing remain in place and are not otherwise dampened through regulation..

Business Models – Constant evolution

Given we know that the route to market which is available today for battery technology in Ireland will rapidly develop to create more optionality to project sponsors in the future, it’s important to plan for this future.

ElectroRoute has been engaging directly with project sponsors to develop a route to market for battery technology based on the commercial prospects and associated route to market requirements of the day, however while keeping an eye to the future and ensuring our framework enables the battery to optimise its revenue and adequately manage risk as the market continues to develop.

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 Battery Storage – Project Development in an Evolving Marketplace appeared first on ElectroRoute.

The development of the battery storage market on the island of Ireland, and indeed throughout Europe, is undergoing a somewhat expected surge in activity owing to the development of both the market structures and more generally the market characteristics, required in order to make a business case for the technology.

Following the recent announcement that ElectroRoute will be providing trading services to the 200MW portfolio of batteries with [Lumcloon], ElectroRoute outlines below the business case for battery storage projects on the island of Ireland at present, and points to the direction of travel for the business case over the years ahead.

DS3 – Lowering the barrier to entry for battery storage facilities

An important source of revenue for batteries in Ireland at present is the DS3 ancillary services regime, named DS3 due to its objective of “Delivering a Secure, Sustainable, Electricity System“.

Established by EirGrid in response to the recognition that the power system would need to develop substantially to operate in a safe and secure manner whilst accommodating increasing penetrations of renewables over the coming decades, DS3 is a wide reaching programme which includes the operation of 12 system services (with 2 further services to be procured in later gates) that can be provided by units operating on the power system.

The table below outlines the full list of ancillary services procured by EirGrid;

Battery technology is an excellent source of capability for a number of these services, particularly the faster acting frequency and reserve products.

The DS3 regime has two routes to market, namely via the Volume Capped auctions and Regulated Arrangements Volume Uncapped (“Regulated Arrangements”) tenders. The Volume Capped auction has completed and contracts are awarded (110MW of Volume Capped contracts were awarded to three battery facilities in 2019) with no current expectation of a new auction. The Regulated Arrangements continue to operate on the basis of a semi-annual tendered service.

Regulated Arrangements

The Regulated Arrangements for DS3 services operate on the basis of a bi-annual gate through which contracted parties can be included as providing units, subject to having passed EirGrid led testing on the battery’s ability to adequately provide the service tendered for.

These arrangements are expected to continue in force until April 2023. At this time, the DS3 contracts allow for two separate 18 month extensions where deemed required. In a recent SEM Committee Scoping Paper on the development of future System Services arrangements, it was outlined that such extensions will be approved by the regulatory authorities where the future arrangements are not yet in place. The contracts will therefore be expected to end should the future arrangements be put in place.

Stacked Revenue Streams

There are three market-based revenues streams available to energy projects on the island of Ireland, namely;

1. Capacity Remuneration Scheme
2. Energy Market Revenues
3. DS3 Revenues

Unlike the Volume Capped contracts, batteries with a DS3 Regulated Arrangement can also seek revenue opportunities in the energy and capacity markets.  However, the DS3 contract is structured to commercially incentivise high availability, so it is important that the route to market is managed to optimise available revenues.

At present, the DS3 rates are reasonably significant for providing units, which has encouraged a focus on this market for developers. DS3 revenues are expected to reduce as more providing units coming to market will have the effect of cannibalising these revenues. We therefore expect increasing reliance on the dynamics and price signals of the energy market to become a key consideration for battery developers in the near/medium term.

Energy Arbitrage – the Heir Apparent

The DS3 budget is limited to €235million per annum and has been increasing on a linear scale since 2015 (€54million per annum budget). We therefore see that with a capped budget and a surge in projects looking to avail of DS3 rates, the only lever which can be moved is the rate of payment.

The regulated tariffs can be altered in limited circumstances prior to the end of term including for circumstances where the budget cap is expected to be breached or where more services are procured than required. As a result, either at the end of contract term or potentially before, it is generally expected that the increased uptake in DS3 contracts will result in a cannibalisation of the tariffs available to projects in future years.

The DS3 rates will therefore over time become more comparable to those attainable for battery technology in energy /arbitrage markets. We see that ensuring an appropriate trading strategy which considers the risk profile of the project sponsor will become an integral part of the business model going forward.

Equally, the design of the battery, and the appropriate selection of import and export capacities for the sites will become a deciding factor in which batteries are capable of transitioning to an arbitrage led busines model.

In the next of our series on battery storage Insights, we explore the limitations and challenges of existing battery developments to adapt to a market less reliant of system services and more focused on capturing optionality in the energy market.

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

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