Introducing our new Head of Energy Market Development, Emeka Chukwureh
21 January 2021
It is a delight to introduce our new Head of Energy Market Development, Emeka Chukwureh, who will play a key role in supporting our growth in Ireland.
Emeka has almost 20 years’ experience in the energy industry, 15 of those in the Irish energy market, involving design, implementation, and development of the Single Electricity Market (SEM) rules. Over that period Emeka has been an active industry participant chairing various working groups of the SEM Modifications Committee, the Markets Committee of the Electricity Association of Ireland (EAI), and the Demand Response Association of Ireland (DRAI).
Emeka’s appointment follows our team’s recent bolstering with two new Senior Consultants Ratnottama Sengupta and Niall Durham, both with deep and diverse experience in their respective backgrounds, across policy and regulatory and flexible asset development, respectively.
Commenting on the appointments, our Managing Director – Peter Connolly, said, “I am delighted that Emeka will be joining us as Head of Energy Market Development. Emeka’s experience and in-depth knowledge of the energy sector will be key in driving forward our ambitions in Ireland. He will join an already impressive team of market experts currently delivering best in class, independent research and advisory support to our customers.” Emeka has added, “I am excited to have been appointed Head of Energy Market Development. I have joined at an exciting time as the energy sector increasingly transitions to a low-carbon future. I look forward to being a part of the team offering independent expert advice to clients to help them navigate along their low-carbon journey.”
Brief Biography on Emeka
Emeka’s energy career started at ExxonMobil, where he was instrumental in the roll-out of new petroleum exploration tools to the geosciences team. In Ireland, he commenced his renewable energy journey in the area of energy analysis and trading at Airtricity/SSE. During his time at Airticity/SSE, he played a key part in designing, implementing, and developing the SEM market rules to enable better wind energy integration. At Enel X, he had hands-on, active management of the Capacity Market’s largest DSU portfolio and the first DS3 System Services from demand-side portfolio.
Most recently, at VIOTAS, he helped implement the international expansion plan for the company into the Australian electricity market, focusing on the frequency market (FCAS). In addition, Emeka has played various key industry roles as a member and chair of various working groups of the SEM Modifications Committee, member of the Ireland Grid Code, chair of the Markets Committee of the Electricity Association of Ireland (EAI), national representative to EURLECTRIC Markets Committee, and chair of Demand Response Association of Ireland (DRAI).
SEM articles of the year: All I want for Christmas is RESS-2
18 December 2020
With COVID-19 dominating our everyday lives, we saw similar trends in our most popular articles for the year. Demand shifts were observed in domestic and industrial settings with working patterns shifting from offices to homes all around the country. It was also a landmark year for the renewables industry with the first RESS auction held this year securing Irelands first grid-scale solar, with several more auctions to look forward to over the next few years.
Based on the number of downloads, these are the top five most popular SEM articles from 2020.
Five: Sail away: Offshore wind vs. RESS
Week commencing 6 March saw the European Commission propose a “Climate Law” enshrining in legislation the objective of achieving climate neutrality by 2050. In this SEM article, we considered the role of wind in achieving the 2050 goal, and Ireland’s role in the European Green Deal.
Four: Changes: Demand falling in SEM
With the unexpected arrival of COVID-19, there was a significant shift in human behaviour. Having been two weeks removed from the Irish Government’s instruction to close schools and advising businesses to allow employees to work from home where possible, we wondered what the impact had been on energy demand across the Island of Ireland. In this SEM article, we looked at the change in demand on weekdays due to the change in behaviour.
Three: Caught in the balance: Assessing amber alerts in the SEM
On 21 January at 10:30am, SEMO announced the issuing of an amber alert. An amber alert is issued when the system margin is at a level where a trip of the largest in-feed would give rise to a reasonable possibility of either a failure to meet system demand, or cause a significant deviation in system frequency from the norm.
In this SEM article, we observed the recent amber alert which was issued, along with the impact of new balancing market modifications.
Two: Tootsie slide: Demand drop
Since both governments on the island of Ireland moved to restrict movement in the light of COVID-19, we observed changes to working patterns resulting in a reduction and shift in demand profile for the island of Ireland. This SEM article looked at how much this has reduced since restrictions have been in place.
One: RESS-won: renewables on the march
4 August 2020 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 were 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 was 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.
System operators warn of System Alerts risk this winter
20 November 2020
EirGrid and SONI issued their Winter Outlook for 2020-21 on 15 October in which they warned that if high generator forced outage rates continue over the winter period there is a risk of System Alerts.
The transmission system operators (TSOs) said the all-island capacity margin this winter is predicted to be 929MW (see Figure 1), with this margin having reduced every year over the past five years. This is mainly due to increasing demand, dispatchable generation exiting the market and increasing generator forced outage rates. They said that, despite the expected margin, if high forced outage rates continue over the winter, there is a risk of System Alerts, particularly when renewable generation is at a low output and support is not available from GB across the interconnectors. In NI, if the forced outage of just one large generator over the winter period coincides with low renewable generation there is a risk of a System Alert. The margin is predicted to be at its tightest at the end of November and start of December.
Of the all-island capacity margin, 786MW is predicted in RoI and 175MW in NI. Given the impact of COVID-19 this year, the TSOs expect the low demand forecasts in the Generation Capacity Statement (GCS) are more applicable for this winter, so they anticipate a peak demand of up to 6,840MW this winter, split 5,210 MW in RoI and 1,690MW in NI. This peak demand is a different day to that with the lowest margin.
The current capacity of demand side response is 553MW in RoI and 95MW in NI and with an availability factor of 40% of maximum capacity assumed, this gives a maximum availability of around 259MW.
Installed dispatchable generation in RoI is 6,454MW, which is set to reduce to 6,226MW with the closure of West Offaly and Lough Ree peat units in December. Installed dispatchable generation capacity in NI is 1,906MW; neither figures take account of outages.
Installed wind capacity grew in RoI by over 450MW in 2019 and now stands at 4,234MW; the contribution assumed for adequacy purposes is 398MW. NI installed wind capacity is 1,276MW (including small scale) with a corresponding contribution of 120MW to adequacy. Solar capacity in NI is 246MW but this does not contribute to adequacy assessments as the winter peak occurs after sunset.
Available net transfer capacity from GB to RoI for winter 2020-21 is expected to be 500MW via the East West Interconnector and 450MW via the Moyle interconnector. In line with the GCS, the TSOs have assume capacity reliance between RoI and NI of 100 MW north to south and 200MW south to north.
Noting that forced outage rates can vary sharply, with security of supply implications, the report notes that rates have increased every year in the last four years, with the all-island, RoI and NI annual forced outage rates currently standing at 10.6%, 12.2% and 6% respectively. Due to the impact of COVID-19, a number of generators had to postpone maintenance outages from the summer months until later in the year, and later in the year to next year, due to the unavailability of resources and materials from overseas. As a result, there are outages of large generator units extending into December and January where typically there would not be any large generator outages in these months. The TSOs said some conventional generators have been and continue to be, constrained off to preserve run hours ahead of the units’ scheduled maintenance to avoid running out of hours ahead of their outages.
Ireland to fall short of existing climate targets under BaU approach
06 November 2020
Published on 13 September, a report by the Irish Wind Energy Association (IWEA) has called for a new policy system to enable the rapid deployment of renewable electricity. The third in a series of four studies which make up the 70by30 Implementation Plan, Building Onshore Wind identifies policy changes required for Ireland to deliver the Climate Action Plan.
Undertaking a comprehensive survey of IWEA membership to establish the current wind energy pipeline, an IWEA Pipeline Analysis Tool (i-PAT) examined how the pipeline would convert into annual MW capacity of onshore wind. The survey revealed that approximately 4,200MW of onshore wind would be installed by the end of 2020, yet an additional 4,000MW will be required by 2030 to meet the Climate Action Plan’s target of 8,200MW.
A Business as Usual (BaU) scenario was developed based on present timelines, which revealed that Ireland will reach a cumulative consented volume of 3,880MW, falling short of existing targets. The report cites low success rates in An Bord Pleanála’s Strategic Infrastructure Development (SID) process, high pre-planning attrition and “relatively long consenting durations.” The 2020 figure also encompasses the cumulative consented wind that will not be built under REFIT.
IWEA identified nine policy improvements to enable Ireland to deliver the Climate Action Plan (Table 1). If all improvements are implemented, the results can be seen in Figure 1. Modelled as the ‘Climate Action Plan’ scenario in i-PAT, it has quantified the additional capacity from the onshore wind pipeline that can be energised in each year to 2030.
However, Figure 2 outlines the onshore wind capacity that will be lost in 2030 along with the additional carbon emissions that will be created if any individual policy fails.
IWEA noted that policies with the greatest impact to reach Ireland’s 8,200MW target for onshore wind in 2030 are: providing enough grid connection offers, developing the transmission grid in parallel with wind farms, and providing an annual route to market via RESS auctions or Corporate PPAs.
To counteract Ireland’s lack of transmission capacity, the report called on EirGrid to further grid reinforcements based on the strength of the future renewables pipeline, and to deliver a timeline to address the needs of the grid, which can be factored in RESS auction bids. A new EirGrid strategy tailored towards grid development will also be required; as well as the exploration of alternative network solutions to drive down costs. To ensure the delivery of renewable capacity needed for 70% RES-E by 2030, appropriate longstop dates will also provide projects with the flexibility to enter multiple auctions. The report finds that if onshore wind is excluded from RESS auctions, it will likely rely on Corporate PPAs. Regular RESS auctions in parallel to an active CPPA market will therefore be essential for Ireland to meet its 2030 targets.
With this in mind, IWEA recommended for the DCCAE to issue a new RESS timeline which promotes annual RESS auctions according to the volume of renewable generation available each year. This will encompass auction quantities to be set using pipeline surveys for onshore, offshore and solar generation. It should also be clarified which auctions will have technology specific preference categories. IWEA’s analysis showcased that onshore renewables would need to compete in annual RESS auctions, particularly to assist in meeting the 2022 and 2025 interim renewable electricity targets.
To resolve commercial barriers to developing renewables, IWEA called for a reduction in the cost of developing renewable electricity to become more competitive with fossil fuels in Ireland and renewable electricity in other markets. A task force should also be established across policymaking, the regulator, System Operators and renewable electricity generators to lower ongoing costs. To counteract regulatory barriers, IWEA proposed for Guarantees of Origin (GoO) to be available to generators to transfer to offtakers under a Corporate PPA and for the CRU to provide clarity on the use of Private Wires in Ireland. Additionally, to make it a condition of planning permission or a grid connection offer that a Large Energy User with a demand in excess of 5MW must procure a CPPA with a renewable electricity generator.
Imbalance prices rise for sixth consecutive month
23 October 2020
This week we delve into system imbalance pricing, and look at the latest movements from the Balancing Market (BM). The BM ultimately reflects the actions taken by the transmission system operator to keep the system balanced. These actions determine the Imbalance Settlement Price (ISP) for each of the half-hourly settlement periods across the day.
The ISP has observed month-on-month growth over the past six months, when looking at the monthly averages. As of 28 September, this has seen the ISP peak at a ten month high of €42.5/MWh throughout September. This has been driven by factors such as, periods of system undersupply, higher than anticipated demand or unplanned outages at power stations.
Despite the steady rise in the ISP, this year has seen fewer instances where the ISP has risen above €100/MWh. This year has seen such events occur in 651 settlement periods, down from 1,379 for the same nine-month period last year. Instead, this year has seen a rise in the number of negative pricing events. These have totalled 925 to date, a 40.0% increase year-on-year. This has been driven by the increased levels of wind installed on the system, which has supported greater periods of system oversupply, notably during storms or periods of strong wind speeds.
New policy measures needed to drive renewable generation
09 October 2020
Published on 24 August, a new report by Energy Storage Ireland and the Irish Wind Energy Association (IWEA) called for action to strengthen Ireland’s electricity grid. The second of a series of four studies which make up the government’s 70 by 30 Implementation Plan, Saving Power outlines how to minimise dispatch down and increase the use of renewable electricity by 2030.
The report called for three key policy measures to reduce curtailment of renewable generation: the development of a DS3+ programme to relieve existing operational constraints to run the system with up to 95% Non-Synchronous Generation (SNSP); to launch the Greenlink Interconnector by 2023, the Celtic Interconnector by 2026 and the introduction of an interconnection policy regime by Q420.
Raising the System Non-Synchronous Penetration (SNSP) from <75% to <95% will be essential for Ireland to meet its target of a 70% renewable electricity system by 2030. EirGrid currently has plans to raise this to 75% in 2021 and has set a goal of reaching 95% SNSP by 2030. Reducing Minimum Generation (Min Gen) from approximately 1,400MW to 300MW has also been outlined. In Figure 1, the challenge of integrating 70% RES-E on the system was quantified by taking the system as it is anticipated to exist in 2020 and attempting to reach 70% RES-E by adding increased wind generation. Both lines represent a 70% RES-E system with the level of curtailment related to changes in Min Gen levels, all other system assumptions based on 2020 system. This resulted in curtailment levels of 44% (Figure 1). Approximately two-thirds of curtailment is removed through the use of a 95% SNSP limit and a 300MW Min Gen limit. Reducing these limits by the provision of sufficient system services is required to integrate 70% RES-E on the system.
The report noted that DS3+ will require new procedures, policies and controls to help manage the system, alongside commercial frameworks to incentivise the deployment of new flexible capability. IWEA has called for System Operators and the Regulatory Authorities to implement a programme to achieve SNSP of >95%; ensure resourcing is in place to deliver DS3+ programme objectives; to work with industry to identify existing barriers; prioritise the dispatch of sources of System Services from low or zero carbon sources; and ensure sufficient System Services are procured to integrate 70% renewable electricity by 2030.
For interconnection capacity, the National Climate Action Plan contained a Marginal Abatement Cost Curve for Ireland to achieve 70% RES-E by 2030. This incorporates the delivery of the Greenlink Interconnector by 2023 and Celtic Interconnector by 2026 to unlock opportunities for surplus renewable generation, minimise curtailment and enable the integration of increased renewable generation.
However, the report highlighted that current Irish policy around interconnection remains unclear and called for the development of a robust interconnection policy framework with high-level agreements between jurisdictions to streamline development, which would reduce uncertainty for public and private developers. The Transmission System Operator (TSO) should also “keep a clear separation of roles, firstly as a developer of interconnector projects and secondly as a transmission system operator.”
To also further interconnector operation, the report explored the implementation of Single Intraday Coupling (SIDC), alongside maximising SO countertrading until SIDC is utilised, in order to export up to 90% capacity during curtailment events. IWEA believes an interim solution is required, which would see both EirGrid and SONI trade to adjust interconnector schedules before dispatch, based on up to date forecast to minimise renewable dispatch down. Additionally, TSOs should monitor and report on interconnector performance during curtailment events to allow the market to identify opportunities for improvement.
To minimise constraints, the report recommended raising transmission grid capacity. A number of key steps were outlined: to begin early transmission development based on the future renewable pipeline, to improve EirGrid’s six-step framework for grid development, alongside the creation of a new grid development strategy. Additionally, EirGrid and ESBN should provide alternative solutions to help deliver RES-E targets and minimise dispatch down, through the use of energy storage and demand side response.
The report also discusses three areas in need of major change: Market Redesign, Dispatch down certainty and Grid 2050. It stated that there is no clear market design implemented for a power system with more than 50% variable renewable electricity and the existing market design is not providing incentives. The report called for the government to provide an alternative route to market via REFIT and RESS (backed by the PSO) to create investments in renewable electricity. Corporate PPAs, carbon price floors and renewable electricity obligations on suppliers could also be ways to stimulate a market for 10-15 year contracts. The report also called for SEMO, via EirGrid and the Commission for Regulation of Utilities (CRU) to create a team to focus on a new market design to facilitate a 70 by 30 power system.
To counteract dispatch down uncertainty, the report recommended that the CRU establish a roadmap to illustrate how dispatch down will be managed over the next decade in order to give certainty to renewable developers, who can then deliver renewable energy at the lower cost to consumers. This will also place the management of the curtailment and constraint levels in the hands of the System Operators, who can then justify investments in solutions such as grid development or programmes.
For Grid 2050, the report advocated for the use of storage technologies in combination with renewable generators for use in electricity, transport, and heat to minimise dispatch down through energy balancing. The report suggests integration of new technologies combined with renewable electricity will minimise dispatch down if appropriate supports are in place. Longer term, government support and regulation via price signals such as new market mechanisms, new tariff structures and new system services will be required to unlock further potential of energy storage technologies and to increase their commercial viability. Additionally, the report advocated for EirGrid and ESB Networks to plan for a fully decarbonised electricity system, to support the electrification of heat and transport and create new forms of demand for wind energy. The network operators should also incentivise flexible demand that can respond to variations in renewable generation and develop additional interconnection or long-term storage to avoid excess renewable power being wasted. The report added that without further policy measures to improve the system in managing increased levels of renewables, dispatch down levels will increase significantly which will create further barriers to renewable generation.
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All-Island wind dispatch-down rises year-on-year
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
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
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
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.
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.
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 firstname.lastname@example.org.
Parties pledge a “revolution in renewables” in draft Programme for Government
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.