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September 2020

Aug

All-Island wind dispatch-down rises year-on-year

Joe Camish
Joe Camish
25 September 2020

On 17 September, EirGrid published its Annual Renewable Energy Constraint and Curtailment Report 2019 which sets out the amount of wind and, for the first time, solar energy, that is available but cannot be used by the system (i.e. the dispatch-down of energy).

Overall, the dispatch-down of energy from wind in Ireland and NI increased from 6% in 2018 to 7.7% in 2019. The report notes that, in 2019, 1,008GWh (7.7%) of the total 11,994GWh wind energy generated was dispatched-down, representing a 301GWh increase in dispatch-down energy since 2018.

However, during 2019 an additional 918GWh of wind energy was generated compared to 2018. The dispatch-down energy from solar resources was 5.6GWh, representing 4.2% of the total available solar energy.

The level of dispatch-down is affected by a number of factors which vary from year to year, such as the amount of wind installed on the system, and the capacity factor of the wind generation. Total wind capacity island wide rose by 467MW in 2018, while the average wind capacity factor increased by 1% to 27% in 2019.

Figure A: All-Island Historical Wind Dispatch Down Percentages

Source: EirGrid

We can expect this trend to continue as more wind capacity is installed across the island. These developments come in light of the Department for the Economy in Northern Island publishing at the start of the month that the renewable share of the generation mix in Northern Island reached a record high in June this year.

The Electricity Consumption and Renewable Generation in Northern Ireland: Year ending June 2020 report was published on 3 September, which details the percentage of electricity consumption in Northern Ireland generated from renewable sources

For the 12 month period July 2019 – June 2020, 47.7% of total electricity consumption in NI was generated from renewable sources. This represents an increase of 3.6% on the previous 12 month period (July 2018 – June 2019) and is the highest rolling 12 month proportion on record.

EirGrid and SONI assess future demand and generation landscape

Josephine Lord
Josephine Lord
11 September 2020

Transmission system operators (TSOs) EirGrid and SONI have issued the All-Island Generation Capacity Statement 2020-29 that sets out expected electricity demand together with the level of generation capacity that will be required over the next ten years. 

Issued on 27 August, the Statement said RoI demand is increasing, and is forecast to increase significantly, largely due to the continued expansion of large energy users primarily data centres, although this growth will be subject to a review once the full impacts of COVID-19 are known later in the year. EirGrid’s analysis indicates that demand from data centres could account for 27% of all demand in RoI by 2029 in the medium demand scenario. This forecast is aligned with EirGrid’s Tomorrow’s Energy Scenarios which predicts a Total Energy Requirement (TER) of 41TWh by 2030.

By contrast, demand in NI is relatively flat, and expected to continue so in the medium scenario until 2023 when the connection of some data centre load drives demand growth. Over the next ten years, demand rises by 4% under the medium scenario, falls by 3% under the low scenario and rises by 12% under the high demand scenario (Figure 1).

For generation, the TSOs seek to paint a picture of how the all-island portfolio might evolve from the present situation of surplus while ensuring the system is adequate to an eight-hour Loss of Load Expectation standard. The report examines the status of each type of generation and issues that impact their future deployment.

In RoI, around 1,900MW of conventional plant is expected to close before the end of 2025, including 885MW at Moneypoint at the end of that period. New conventional plant that has been successful in T-4 auctions and assumed available from 2023-24 totals nearly 1,400MW at its de-rated capacity. In NI, Kilroot ST1 and ST2 will cease operation in 2023, representing 476MW, as it did not qualify for the T-4 2023-24 auction, while EP Kilroot at 383MW is due to come online from 2024.

The North-South Interconnector is assumed to be available in 2024; currently the capacity reliance value on the existing interconnector is 100MW north to south and 200MW south to north. The East-West Interconnector and Moyle Interconnectors are assumed to be de-rated at 60% to 300MW and 270MW, respectively. Two further interconnectors are planned: Greenlink, with target availability 2023-24 and the Celtic Interconnector, with target availability 2026-27.

The report assumes that RoI’s renewable targets will be achieved largely through the deployment of additional wind-powered generation. Connected, contracted and in-progress grid connections amount to around 9GW, including 6GW of wind, around 2.5GW of solar and around 0.5GW of battery projects.

This year’s Statement presents an example renewable generation portfolio for RoI which could achieve the 2030 target of 70% renewable electricity (RES-E) (Figure 2). In 2019, renewable generation reached 35.7%, with a target of 40% by 2020. The projection is based on this year’s median demand forecast, and the statement says that under it, the diversity of the renewables mix increases due to reducing levelised costs and from auction designs. Large scale onshore wind, offshore wind and solar PV are expected to be most prevalent, while carbon capture and storage could be developed to further decarbonise fossil fuel generation. The first Renewable Electricity Support Scheme auction (RESS-1) provisionally awarded 2,237GWh of contracts in August, which accounts for around 10% of the amount forecasted to be required to meet the 2030 targets.

For NI, the Statement notes that draft policy options with respect to energy policy and decarbonisation are due from the DfE this winter, with any target expected to be similar to those set in other regions of the UK. In 2019, 39% of electricity consumption came from renewable sources, most of it from wind power. In the absence of an approved energy strategy, the TSOs have based the expected growth of wind capacity on the volumes of applications that have accepted a grid connection offer: 245MW of wind generation has accepted a grid connection offer (excluding generation under 5MW). This increases installed capacity from a little under 1,300MW in 2019 to just over 1,500MW from 2024 onwards.

For its generation adequacy studies (Figure 3), the TSOs have assumed that the second North South Interconnector will be available from 2024. The all-island system will then be capable of operating electrically as one, meaning all the generation capacity from both jurisdictions can meet the combined load. New generation that was awarded a contract in the T-4 20203-24 auction is included in the studies. Any existing plant that entered any capacity auctions to date are also included, even where unsuccessful, unless formal notices of closure have been received.

For RoI, the system starts in a position of significant surplus, but this is eroded as demand is forecast to increase and some generation plant is shut. To meet specific security of supply issues, from the T-4 2023-24 auction a Dublin regional location requirement is included. Noting how the adequacy situations worsens, the report said this demonstrates the need for new low-carbon plant to be commissioned from 2026, with only the low demand scenario remaining in surplus. For NI, the median demand scenario is in a surplus of around 290MW for most years, reflecting the flat demand forecast. In the all-island scenarios from 2024, all scenarios see reducing surpluses over time due to increasing demand and assumed plant closures. The low availability and high demand scenarios show deficits from 2026 and the Demand Level 8 (which matches the level of demand chosen by the Least Worst Regrets methodology for the calculation of the Capacity Requirement in the 2023-24 T-4 auction) shows deficits from 2028.

Demand trends: August sees highest demand since March

Joe Camish
Joe Camish
31 August 2020

This article was originally published on 25 August 2020 in our ‘SEM and commodity pricing report’.  

In this week’s blog we take a look at the latest fundamental developments impacting power prices in the SEM. This will see us take a look at wind generation in the SEM this year, while assessing demand trends since COVID-19 mitigation measures were eased as Ireland transitioned into Phase 3 of its roadmap for easing restrictions. 

Wind generation  

Figure A observes the average wind output per month out until the end of July and compares them with the levels experienced in the previous year.  

 

The analysis shows that so far this year wind generation has averaged 11.7% higher compared against the same time period last year. This year has seen wind average 36.7GWh, 3.9GWh higher than in 2019 (32.8GWh). 

2020 has also seen only two months have lower monthly output on average against its 2019 counterpart, these exceptions being July (9.4% lower) and April (36.8% lower). The remaining five months of the year have typically averaged 26.6% above the previous year.  

Over this same period day-ahead power prices in the SEM have fallen considerably, partly driven lower by the more frequent periods of higher wind output mentioned above, which has displaced more expensive thermal generation out of the generation stack. Power prices from January to July have averaged 42% lower on average year-on-year. However, this is not to dismiss the impacts of falling power demand from COVID-19 mitigation measures, along with the longer-term trend of falling gas prices. 

Power demand  

Since June we have noticed a steady increase in demand levels, which had fallen throughout March to May. As we come to the end of August demand levels sit at a daily average of 93.3GWh – making them the highest levels observed since late March. Last week saw daily demand peak at 100.3GWh on 18 August, a near four-month high.  

Since Phase 3 of the Irish governments roadmap for easing restrictions began back on 29 June weekday demand levels have somewhat plateaued – averaging 94.7GWh. However, we have observed in the past two weeks upward growth in demand, with levels averaging 98.3GWh last week, representing an increase of 1.6GWh on average for weekday demand since Phase 3 went live.   

For more content on wholesale price and fundamental developments in the SEM do check out our rebranded SEM and commodity pricing report. This is a weekly report covering Irish power prices, along with NBP gas and wider international commodity markets (Brent crude oil, coal and EU ETS carbon). For more information please contact j.camish@cornwall-insight.com 

Parties pledge a “revolution in renewables” in draft Programme for Government

Neil Mearns
Neil Mearns
14 August 2020

This article was originally published on 14 July 2020 in our ‘Energy Spectrum Ireland’ publication. 

The leaders of the Green Party, Fianna Fáil and Fine Gael signed off the draft Programme for Government (PfG) on 15 June. According to the PfG, energy will play a “central role in the creation of a strong and sustainable economy over the next decade” and Ireland will undergo a “revolution in renewables”.

The energy policies are described under the Green New Deal section of the document and are motivated by a concern with accelerating climate change. The parties are committed to an average 7% per annum reduction in overall greenhouse gas emissions from 2021 to 2030 (a 51% reduction over the decade), and to achieving net zero emissions by 2050. They will introduce the Climate Action (Amendment) Bill 2020 into the Dáil within 100 days which will, among other things make the adoption of five-year carbon budgets a legal requirement. A Climate Action Fund will also be established in law within 100 days.

The parties are committed to publishing a plan to deliver 5GW of offshore wind capacity by 2030 – up from the current target of 3.5GW – and will aim to deliver at least 70% renewable electricity by this date. A “whole-of-government plan” setting out how to deliver this target will be produced. The first Renewable Electricity Support Scheme (RESS) auction will be held by the end of 2020, with auctions held each year thereafter, including the first RESS auction for offshore wind in 2021. There is also ambition to develop a Solar Energy Strategy for rooftop installations.

The plan mentions support for the clustering of regional and sectoral centres of excellence in the development of low carbon technologies and investment in ‘green’ hydrogen R&D.

The parties will implement a new National Energy Efficiency Action Plan to help reduce energy use and educate about behavioural aspects of energy efficiency such as building and data management. The PfG outlines an ambition to designate a National Retrofitting Delivery Body by the end of 2020. It also aims to deliver a National Aggregated Model of Retrofitting reaching over 500,000 homes by 2030, as part of the EU Renovation Wave. Local authority retrofit programme pilot schemes will commence in early 2021 to test key elements of the national plan.

On heat, the parties pledge to support the development of combined heat and power systems through a range of incentives to encourage uptake. The PfG describes new initiatives around heating systems and regulatory environment to support the development of district heating. A feasibility study on establishing a district heating authority will be published and setting new targets for district heating as part of a new strategy will be considered. There will be a targeted programme to install heat pumps in homes that are already suitable for the technology as part of a plan to install 600,000 heat pumps by 2030.

A new Public Sector Decarbonisation Strategy for 2030 will be published. This will include the development of policies to ensure greater use of energy performance contracts within the public service.

There is ambition to accelerate the electrification of the transport system, including electric bikes, electric vehicles, and electric public transport. There is support for a ban on new registrations of petrol and diesel cars from 2030.

The PfG commits to a Just Transition, with the transition out of peat in the Midlands the first test of this.

It commits to end the issue of new licenses for the exploration and extraction of gas, on the same basis as the recent decision in relation to oil exploration and extraction.

RESS-won: renewables on the march

Conall Bolger
Conall Bolger
05 August 2020

Yesterday will be remembered as a good day for the Irish renewables industry, with the level of supported renewables capacity set to grow by over a quarter in the next 2-3 years.

After years of waiting, the first Renewable Energy Support Scheme auction (RESS-1) results are here (provisionally, pending appeals). Individual prices are confidential though the average published prices were: community projects – €104.15/MWh, solar – €72.92/MWh and all projects – €74.08/MWh.

The headline will be the 796MW of solar projects securing contracts. The big implication is, assuming successful delivery, Ireland could have 800MW grid-scale solar projects in the next couple of years. The solar industry lobbying has delivered.

However, the wind industry is not a loser here. While the capacity of winning projects was lower, 479MW, higher wind capacity factors mean that nearly twice the volume of onshore wind output is forecast to be supported than solar. Only a relatively small proportion (21MW) of the bidding wind projects did not secure a contract.

A big takeaway is the price level. The average prices obscure any variation in the bid prices. Having modelled Irish solar projects, it’s clear that developers placed reasonably lean bids to secure contracts. A lot of the wind projects are likely to be operating under less generous pricing than under previous Renewable Energy Feed-in-Tariff (REFIT) contracts.

The all projects category average price being higher than the pure solar average price suggests that a number of higher-priced solar projects didn’t or couldn’t win in the solar category and secured contracts in the all projects category. The price level and competition suggest there was also some canny bidding in the community pot.

The outcome of the auction will probably satisfy policy makers considering some of the wilder predictions pre-auction, though the price level is higher than recent auctions in other jurisdictions.

One driver for that may be network costs, which are not insubstantial.

Another talking point, the RESS contracts not being indexed to inflation, will have increased bid prices. It adds 20-30% more to a project’s operational costs, depending on assumed rates. Differences between similar bids could come down to bidders’ respective views on inflation levels. The freshly minted Department for Climate Action, Communication Networks and Transport may reconsider that aspect of design in future auctions.

While there is scope for participants to express dissatisfaction, within the RESS-1 process the only relevant grounds for appeal are procedural ones, and the auction appears to have been run as per the terms and conditions. The Minister has some powers to intervene; Minister Ryan’s return to the energy portfolio may involve him fielding calls from project owners. Our expectation is, however, that the Minister may wish to avoid intervening to maximise auction credibility.

The focus for many now shifts to ESB Networks delivering connections to meet the RESS delivery deadlines. Staff at the distribution company can expect to be hearing quite regularly from RESS project developers seeking updates on progress.

EU COVID-19 stimulus plan – EU ETS impacts and environmental policy developments

Joe Camish
Joe Camish
31 July 2020

This article was originally published on 28 July 2020 in our ‘Irish energy market bulletin’ publication.  

Two weeks ago saw the European Commission’s proposed €750bn stimulus plan and revised €1.1tn proposal for the EUs next long-term budget (2021-2027) agreed upon by EU member states at the European Council.

The plan dubbed – Next Generation EU – sees the Green Deal at the heart of the recovery package, below we have picked out what the deal means for the future of the Emissions Trading Scheme (ETS) and wider EU environmental policy.

The overall recovery and budget package will total €1.8tn (€750bn recovery plan, plus the revised €1.1tn budget). Based upon the overall package, 30% has been earmarked for climate action, supporting the objectives of EU climate neutrality by 2050 and the Unions 2030 climate targets. The report noted that by the end of the year the EU will raise the ambition of its 2030 target – currently set to “at least 40%” below 1990 levels. For some context of what the target could be revised to, Germany has recently come out in support of a 50-55% target.

In order to address the social and economic consequences of the EUs 2050 neutrality target, a Just Transition Mechanism, including a Just Transition Fund, will be created. The fund will support fossil fuel reliant regions towards net-zero. The budget for the fund was originally proposed at €40bn, though a €17.5bn budget out to 2027 was agreed upon. Member states who have not committed to net-zero by 2050 will only be able to access 50% of their allotted allocation.

The report went on to add a number of developments impacting the ETS. The first of these was the commitment to introduce proposals in the first semester of 2021 on a Carbon Border Adjustment Mechanism (a carbon border tax) to help avoid carbon leakage. This will start with a number of selected sectors and gradually be extended over time. The plan outlined the potential start date of no later than 1 January 2023.

In the same spirit the Commission will also put forward a proposal on a revised emissions trading scheme – potentially exstending it to account for aviation and maritime sectors.

The full document from the special meeting of the European Council and be accessed here.

Changes: how our Spectrum service is evolving

Cathal Ryan
Cathal Ryan
20 July 2020

This article was originally published on 9 June 2020 in our ‘Energy Spectrum Ireland’ publication. 

Since Cornwall Insight launched the Energy Spectrum Ireland Service in 2015, it has been providing insight on key developments in the energy markets in Ireland. With the macro market trends of decarbonisation, decentralisation and digitilisation, on top of what was already a newly constructed market mechanism, namely I-SEM, the level of complexity in the energy market has risen to new heights. Due to these factors and strong feedback from you our client base, we have enhanced the offering around our market research subscription services.

With our Irish team growing and our presence in the market strengthening, it is appropriate to undertake a review of our product offering to ensure we are maximising the insight we can offer. This will be our last edition of Spectrum in its current format and we anticipate the changes we have made will result in our Spectrum service delivering greater insight and value than before.

Our Spectrum service contains two parts, The Ireland’s Energy Weekly Bulletin and Energy Spectrum Ireland.

Ireland Energy Weekly Bulletin

The Weekly Bulletin will continue in the same format as before. Our evaluation and feedback from you indicated that it provides a valuable weekly view of all developments in the energy market. However, the review also suggested that we should change the timing and therefore, we have taken the decision to move the Weekly Bulletin from a Friday to a Monday. With this move we hope that by delivering the Weekly Bulletin to you on a Monday morning it will inform and assist as you plan out the week ahead. The Weekly Bulletin includes all energy related news across the island of Ireland and will keep you up to date on developments as they happen in the Irish market. The format will remain the same with the stories being factual and providing you with the necessary links to original sources.

These changes will mean the Weekly Bulletin service will continue to inform you of all the developments in the Irish energy market as they happen.

Energy Spectrum Ireland

Our Energy Spectrum Ireland (ESI) publication has long been our flagship publication, produced monthly where we provide insight across the key developments in the single electricity market. With this in mind, we carried out our review with the aim of delivering a greater depth of insight in a more accessible way. Said another way, our insights will be presented in such a way as to be genuinely actionable.

The main article of each issue of ESI has been the Perspective piece. This is where we conduct an in-depth look at an aspect of the market. It is with a heavy heart that we have decided to discontinue the Perspective article of Spectrum to replace it with greater market insight across every other article in the publication. In this issue you will notice we have a usual number of long articles; 2 in Policy, 2 in Regulation and 2 in Industry structure.

Normally a comment is provided at the bottom of each article, to highlight the key points in the article and provide more specific context. This is provided in italics at the bottom. This method is our writers’ way of providing insight on emerging news stories every month and allows us to give you our insight on market developments. In addition, we include shorter stories taken from our Weekly Bulletin. In the new ESI, we will remove these shorter stories. These stories are already included in the Bulletin and we believe that they do not provide you with added value when they are presented in ESI. In future, we plan on just having one-page news articles with our insight provided after each article from several different viewpoints.

The new Spectrum

Next month’s issue will be our first issue in the new format, with commentary provided at the bottom of each article from 5 viewpoints as well as a general comment on the impact of a news story. We will keep the same format with Regulation, Policy and Industry Structure as three distinct sections, but we will have a minimum of 6 and a maximum of 10 stories spread across the issue. The new version will arrive at your inboxes on the second Tuesday of the month as before and will profile the previous month’s news.

Viewpoints

The insight we provide will be from the following viewpoints:

  • Assets
  • Wholesale
  • Retail
  • Large Energy Users
  • Regulation and Policy

Each viewpoint will be provided by one of our market experts who will give their insight to each news story after you have read the factual news as written by our writers.

After each article there will be a page with our insight on it, which will be filled with our market experts’ thoughts and commentary. A sample of what this will look like is in Figure 1.

They will also provide a simple impact rating based on this viewpoint of either positive, neutral or negative, as shown in Figure 2.

We have selected these five viewpoints as we feel they effectively cover the differing perspectives that can truly impact your business. We believe all those engaged in the provision of energy to consumers in Ireland will find our viewpoints to provide value in understanding the impact of all major market developments. Each viewpoint has a rather broad definition, which will allow us to cover a broad spectrum of interests. Let us go through the 5 viewpoints.

Assets: Owners, operators and developers of assets which supply electricity to the national grid.
This viewpoint covers all types of generation assets, developer sizes, owners, managers and operators of assets who produce electricity to be used on the national grid. Those in this part of the energy markets in Ireland are indirectly or directly involved in the next viewpoint, which is Wholesale.

Wholesale: Those involved in markets where energy is traded, hedged, bought and sold.
This viewpoint observes the market from the point of view of someone who is actively involved in the buying and selling of electricity on a regular basis. Those engaged in PPAs are also included in this viewpoint.

Retail: Retail suppliers who sell energy and related services to end users.
This viewpoint concerns those who sell electricity to final consumers, both domestic and non-domestic.

Large Energy Users: Large energy users who actively participate in energy markets.
This viewpoint will take the angle from those who generally consume energy but are now on the path to becoming prosumers. Anyone who operates demand-side units, flexible onsite generation and system services as part of the operation of a site whose primary use is not energy generation are likely to benefit from the views expressed here.

Policy and Regulation: Policy and regulatory commentary.
This viewpoint is slightly different from the others. Its intention is to give a view of what the potential regulatory pitfalls that may occur, or what may be coming from a regulatory point of view.

Complete new look

These changes are intended to deliver added value to your business. As part of our review we have also taken the opportunity to revamp the style of the publication, giving it a whole new look and feel. ESI has been published in a two-column format to date and we will be changing this to a single column of text format. This will make the articles more flexible and visually accessible for a range of electronic devices. It will also allow us to include more graphical representations within the content.

To conclude, these changes will allow us to give you more insight into market developments as they happen. We anticipate that there may be some questions regarding the changes we are making and if you have any, please contact me on c.ryan@cornwall-insight.ie or +353 (87) 6139804.

Demand changes since the easing of COVID-19 measures

Joe Camish
Joe Camish
03 July 2020

This article was originally published on 14 June 2020 in our Irish Energy Market Bulletin. 

In this week’s focus we will have another look at the ongoing impact on demand from COVID-19 mitigation measures. This comes in the light of the easing of restrictions in both Northern Ireland (NI) and Ireland.

On 18 May, the Irish government started its Roadmap for Reopening Society and Business, which saw the easing of COVID-19 measures over a series of five phases. This has since been accelerated and seen a reconfigured roadmap consisting of just four phases, with Phase 3 beginning on 29 June and Phase 4 on 20 July. The NI Executive published a similar phased approach to easing restrictions, consisting of five stages.

Since the start of Phase 1 to date, daily weekday demand has risen by 3% (3GWh) on average, with current weekday demand levels averaging 94GWh. This period has also seen peak power levels increase by 7% (0.3GW) on average, with current peak demand sitting at around 5.0GW. The modest increase in demand is partly due to many workers still being advised to work from home if possible. While many larger industrial or commercial business have either only recently restarted operations or are operating at a reduced capacity.

When compared to demand levels when we saw the first major announcement on 12 March in the ROI, demand remains 14% lower on average when compared to the first week of restrictions (108.7GWh).

However, when looking at this we will have to factor in the natural change in demand patterns as we enter deeper into the Summer, when compared with the backend of the winter season.

 

CRU implements COVID-19 supply suspension scheme

Josephine Lord
Josephine Lord
19 June 2020

On 1 May, the CRU set out the details of its decision to implement a temporary supply suspension scheme for eligible SME electricity and gas customers due to the impact of the pandemic.

It said that the unique and extraordinary circumstances of the current situation require a modification to the current approach to network charging. The objective for the scheme is to:

  • Avoid unnecessary disconnections and reconnections for SMEs.
  • Reduce the charges incurred by SMEs whose premises are temporarily closed due to COVID-19 restrictions.
  • Facilitate SMEs rapidly returning to operation once the COVID-19 restrictions are lifted.
  • Support energy suppliers who would continue to be liable for related use of system and energy charges during COVID-19 restrictions.
  • Mitigate the risk of bad debt and liquidity constraints for the energy sector during and post the COVID-19 period.

The regulator considered that it is appropriate to facilitate SMEs be able to have the financial advantages of a physical disconnection where such disconnections are not possible during the current travel restrictions.

Any customer that avails of the scheme will have no energy or network charges billed for their business premises supply point for the duration that the measure is in place. In effect, the consumption for their supply point would be estimated at zero and their fixed network charges suspended.

All but one of the eligibility criteria that an electricity or gas business customer must fulfil are identical for both fuels:

  • The customer is not an essential provider, as defined by the government in the context of COVID-19.
  • The customer was trading before 13 March 2020.
  • The customer’s premises have been closed as a result of the COVID-19 restrictions and will remain closed for a continuous period from 28 March and the date the relevant COVID-19 restrictions are lifted.

In addition, electricity customers must be in the DG5 or DG6 use of system charging categories, while gas customers must be Non-Daily Metered (NDM) Industrial & Commercial customers.

As part of its decision, the CRU separately directed ESBN, GNI and EirGrid to finalise the processes to implement the scheme. The regulator said ESBN and GNI proposed different methods that can be implemented quickly, will not require changes to the market systems and can by unwound at the end of the current COVID-19 restrictions. It set out the key requirements in both the electricity and gas processes. These include that suppliers are to maintain records of the request and be responsible for communications with the customer. To manage and track the scheme other market procedures, such as change of supplier, will not be carried out at a site while it is in place.

Where the supplier or network operator becomes aware that a customer in the scheme was operating during the period or is otherwise ineligible, the relevant charges will be applied. If a customer who was eligible but becomes ineligible due to a change in circumstances, the customer must inform the supplier within five days.

Under the principles set out for the scheme, the CRU said the network companies will subsequently recover all costs that have not been recovered during the period of the COVID-19 supply suspension, through the regulatory approved network tariff process in “subsequent tariff years”.

The scheme is due to be in place for three calendar months but may be terminated before this; it will be reviewed and evaluated while in operation.

This was a timely decision that will help businesses that have been temporarily closed by the crisis. However, it was also a practical recognition of circumstances. In the aftermath, the CRU will need to determine the scale of the costs to be recovered, how to implement it and over what timescale.

SEM Focus: Day-ahead power turns negative to record low

Joe Camish
Joe Camish
05 June 2020

Last weekend saw the day-ahead power price average negative for only the second time since the new trading arrangements commenced back in October 2018. The first such negative pricing event occurred on 5 April, when the day-ahead power price averaged -€2.5/MWh.

Saturday 23 May saw the power price outturn lower at -€10.1/MWh on average, representing a €14.9/MWh reduction compared to the previous day.

The day-ahead market started the day at -€1.0/MWh, before falling as low as -€41.1/MWh at 05:00 – making it the lowest price for an hourly settlement period since at least 28 October 2019. In total, the day observed 18 consecutive periods of negative hourly settlement periods from 00:00 to 17:00. The remaining periods on the day rose positive, before ending the day at €0.0/MWh.

Price depression on the day would have been impacted by strong wind output. This saw wind production account for 68.4% of the generation mix on average throughout the day. Low weekend demand would have also been a factor when coupled with the days strong wind generation. Demand on the day totalled 81.0GWh, the lowest daily demand since June 2018, aided by warm temperatures.

The same day also saw intraday markets one and two average -€10.0/MWh and -€1.0/MWh respectively. These represent the lowest prices for these markets since at least March 2019. The intraday one market also averaged negative on 22 May at -€1.0/MWh.

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