Written Evidence submitted by AES UK Ireland (EEE0015)

1. AES UK & Ireland is part of The AES Corporation (NYSE: AES), a Fortune 200 global energy company, headquartered in Arlington, Virginia, which works across the energy value chain in 16 countries. AES provides affordable, sustainable energy through our diverse portfolio of distribution businesses as well as thermal, renewable and storage facilities.
2. AES has operated in Northern Ireland since 1992 and we are the region’s largest electricity generator, providing approximately 60% of generation capacity in 2017. In addition, as the largest Independent Power Producer on the Island of Ireland we supply 10% of energy demand across the all-island electricity system. AES owns and operates Ballylumford and Kilroot Power Stations in County Antrim, plus the 10MW Kilroot Advancion® Energy Storage Array. Most of this capacity has recently undergone extensive environmental upgrade to comply with EU emissions reduction legislation.
3. AES UK & Ireland is comprised of two standalone companies, AES Kilroot Power Limited and AES Ballylumford Limited.

What are the positive and negative effects of the Integrated Single Energy Market (I-SEM)?

4. As in the SEM, consumer energy bills in the I-SEM will be composed of wholesale market costs, network costs, retail costs, and policy costs.  In the wholesale market generators receive three forms of compensation for the services provided: capacity, energy and system services payments. Of these three, energy payments are the main driver of wholesale market costs to customers. These payments for delivered energy comprise over three quarters of 2017 SEM costs for NI consumers and we continue to forecast that this will be the case under the ISEM arrangements.
5. There has been significant recent focus on the savings from the first T-1 ISEM capacity auction.  However, AES would highlight the fact that a generation unit with lower capacity costs may have higher energy (fuel) costs and far lower capacity factors (a measure of how often the technology is run at full capacity).  When dispatched such units will increase the energy cost borne by consumers, offsetting capacity savings.
6. The first I-SEM T-1 capacity auction is the first of a series of T-1 auctions to transition the market towards 2022/23 when the first T-4 auction to be held in Q4’18 or Q1/’19 delivers capacity.  These T-1 auctions focus on only on the capacity cost element which is designed to cover a generator’s fixed costs. Exit signals have been sent to a number of generator units on the Island which are mid-merit units, which can deliver increased levels of the system services and also cheaper energy compared with other peaking units which have cleared in the auction.
7. AES has received confirmation that SONI undertook an assessment of the results of the T-1 auction out-turn and have confirmed that the AES Kilroot coal units are not required to serve capacity or operational needs.  We have asked both the Utility Regulator and Eirgrid Group for this analysis but to date this has not been forthcoming. AES believes that it is imperative that this analysis is made available on a transparent basis explaining the impact of Kilroot coal unit closing on medium and long-term system security and cost to customers.
8. To be successful, the I-SEM must demonstrably work for Northern Ireland and the Island of Ireland. Significant emerging discrepancies in processes and supply margins must be addressed to avoid prejudice to NI market participants and consumers, a negative impact which the I-SEM was explicitly designed to avoid. For example, as system operator the EirGrid Group is responsible for assessing the distinct needs of load centres (cities or large energy use areas such as Belfast, Cork and Dublin) as well as places where the grid infrastructure is less well connected than is optimal (such as the North-West of Northern Ireland or the constrained export zone out of Dublin into the Midlands). The ISEM needs to ensure that these system services are available in places where the grid is less robust, and that unintentional exit signals are not sent to needed generation plant as a result of one pillar of the I-SEM process alone.
9. In October 2017 SONI’s Operational Constraints Update declared that, “There must be at least one Kilroot unit on load when the NI system demand exceeds 1400 MW and 2 units are required above 1550 MW. This operational constraint is required to ensure voltage stability in the Belfast area and to prevent the requirement for an inter area flow reduction in a post fault scenario”[1]. On 19 January 2018 (post preliminary ISEM capacity auction results), SONI published an updated Operational Constraints Update which removed the Belfast Load Centre Voltage Stability dispatch requirement, with retroactive effect from 5 January 2018[2]. No equivalent changes were made by EirGrid for load centres in the South.
10. Despite the unconsulted upon change in constraint rules, actual dispatch of Kilroot from 5 January to 10 February inclusive was such that when the Kilroot units have been available and the NI demand has gone above 1400 MW, at least one Kilroot unit has been on 96% of the time. In the context of the I-SEM go-live date on 23 May and the expected removal of Kilroot’s coal units due to the results of the T-1 capacity auction, AES would question the discrepancy in approach to load centre stability between Belfast and cities in the South. We would encourage the publication of the technical assessment carried out to determine that the Kilroot coal units are not required, so it could be compared to the October 2017 declaration of Kilroot’s criticality.
11. Further in parallel with this publication, SONI and the UR should outline (i) details of the clear rationale for the change to their proposed operation regime, (ii) details of the risk assessment carried out to ensure they were not taking on any increased level of risk in how they operate the NI electricity system on behalf of Northern Ireland electricity consumers without such consumers being fully aware of, consulted with, and comfortable with, any potential additional risk.
12. There is an evident divergence in the plant closure process for generation assets in NI and Ireland and this divergence has introduced material disadvantages for investors in energy infrastructure in NI under I-SEM. In December 2015 the UR approved a NI Grid Code modification introducing a 36 month Grid Code closure (despite objections from AES and other generator participants) notice process, bringing it in line with obligations in the Irish Grid Code. This 36 month notice period makes sense if a plant is unsuccessful in the yet to be held T-4 auctions, providing sufficient warning to the market of its departure before the arrival of new generation in 48 months’ time. However, the three-year notice period is entirely inconsistent with the transitional T-1 capacity auctions which could provide commercial exit signals on a much shorter time frame. In the case of the 2017/18 T-1 auction this has provided only four months between auction results and the end of current capacity payments on 23 May.
13. In recognition of this conflict, on 18th December, the date the provisional auction results were due to be published, the Irish Commission for the Regulation of Utilities (CRU) published an information paper Regulatory Approach to Maintaining Local Security of Supply in Electricity[3], which acknowledges that I-SEM’s T-4 timeline and the 36 month Grid Code notification period are at odds with exit signals sent to generation capacity which is unsuccessful in the T-1 capacity auction process. The information paper accepts that licensees must be able to finance their generation activities during the notice period and establishes a process to maintain interim security of supply as the market transitions to the new capacity regime. This approach allows for an orderly exit of generation capacity and fulfilment of statutory closure requirements.
14. In comparison, on 20th December 2017 (the same day as the T-1 provisional capacity auction results) the Utility Regulator for Northern Ireland (UREGNI) published a Generation Plant Closure Process[4] . AES sought clarification by email from UREGNI if they were going to publish a similar document to the CRU document published on 18th December, to which UREGNI confirmed that the approach in the CRU information paper would not be introduced in NI.
15. Having been unsuccessful with three units in the T-1 auction, AES now has no option but to follow the Plant Closure Process in seeking a derogation to close Kilroot Power Station’s thermal units from ISEM Go Live date of 23 May 2018, when they will become financially non-viable. On a similar basis we have had to seek a derogation to close the unsuccessful Ballylumford B station unit at the end of December 2018 (when it falls out of contract with SONI). These derogation requests are currently under consideration by UREGNI, with analysis on the security of supply implications being undertaken by SONI and due to be shared mid/late March.
16. As a matter of principle across both I-SEM regions, if generation units are found by the system operator to continue to be required on the system and therefore a derogation request is refused, then adequate commercial arrangements must be secured to enable the generator to finance their mandated ongoing activities.
17. If generation units are found by the system operator to be surplus to requirements, it is imperative that a derogation to allow timely closure will be issued by the regulator, mindful of a licencee’s legitimate need to adequately fund their activities. Granting a derogation in such a scenario will not affect security of supply and would allow the generator to conduct an orderly and managed exit, including honouring commitments to staff, suppliers, offtakers and all key stakeholders.
18. Beyond these scenarios, a finding that units were not required for security of supply or other reason but in which a derogation request was not granted, would send negative investment signals about the I-SEM and/or the region.
19. A significant effect of the I-SEM market design has been the introduction of unit specific bidding i.e. allocating costs on a unit by unit basis. As a number of market participants operate power stations with multiple generation units across which fixed costs cannot be divided on a unit by unit basis, this has caused challenges in assessing comparative pricing for each unit. The resulting higher bid costs on an artificial unit by unit basis has led to some of the most frequently called upon plant (including Kilroot and Viridian Group’s Huntstown Power Station) being sent exit signals.

What are the broader implications of the Kilroot and Ballylumford power station closings?

20. Since the publication of the provisional results on 20th December 2017, two key questions have been asked of UREGNI and SONI:
1. Where will Northern Ireland get the equivalent energy when the Kilroot coal units and the Ballylumford B station unit close?
2. What will the cost of this additional energy be, assuming it can be obtained when required?
21. To date AES is not aware that these key questions have been answered, and is only aware that what has been stated publicly is that SONI believes that sufficient “capacity” has been procured in the T-1 process.

22. As has been highlighted above since their announcement, the T-1 auction results send a strong exit signal for 36% of dispatchable generation capacity in Northern Ireland to close in 2018. Both of Kilroot’s coal fired generation units (513 megawatts (MW)) will have no capacity market revenue from 23 May 2018 when the current market ends and therefore will be unable to cover their fixed costs. One Ballylumford B Station unit (145 MW) is expected to close on 31 December 2018 when its current contract for local reserve capacity expires.
23. One Ballylumford B Station Unit (145 MW) and six Open Cycle Gas Turbines (OCGTs) (238 MW) across both the Kilroot and Ballylumford sites were awarded T-1 contracts and will continue to operate until September 2019. Operation beyond September 2019 will be subject to the results of subsequent ISEM T-1 capacity auctions.  AES Ballylumford has a 600 MW CCGT which is under contract to Power NI’s Power Procurement Business (PPB) until September 2023 and PPB are responsible for bidding this CCGT into I-SEM whilst it is under contract.
24. The OCGTs are subject to a 500 hour annual running limit due to environmental constraints. Unlike the unfettered running hours that each of the two Kilroot coal unit has (on average over 6000 hours run over the past three years), these OCGT units cannot run beyond this time restriction without breaching binding Northern Ireland environmental regulations.
25. In addition to capacity and energy, Kilroot has provided Harmonised Ancillary Services to the SEM. The replacement I-SEM System Services will be procured partly from a competitive tender through the DS3 process. As of 23rd February 2018, the overdue DS3 Volume Capped Procurement Process consultation has not been published, suggesting that the auction itself and delivery of new plant to provide system services (expected to be one year after auction results are published) will not be delivered in time to replace Kilroot units and the Ballylumford B station unit.
26. Ordinarily the impact of such supply restrictions on the ability to meet forecast near-term demand (the “generation security standard” if “normal operational situations” are compromised[5]) would be shared in the EirGrid Group’s annual Generation Capacity Statement. The most recent 2017 Generation Capacity Statement forecasted a 2019 surplus of only 200 MW. However, the additional loss throughout 2018 of 658 MW from the three AES units sent exit signals would clearly seem push NI into a significant deficit from 2018 onwards, accelerating towards the supply deficit forecast for Northern Ireland for 2024 in the Generation Capacity Statement.
27. Despite assurances from SONI and UREGNI that security of supply will not be compromised by the loss of this 658MW of capacity, the expected level of transparency around these calculations has not been shared with market participants to date.
28. In addition to the lack of transparency around the technical assessment, AES would welcome the publication of SONI and UREGNI assessment of the impact of the three AES units’ closure on energy costs for NI consumers due to increased dispatch of significantly more expensive OCGTs and Demand Side Units. As outlined in paragraph 3, energy, not capacity, costs are the greatest driver of consumer bills.
29. Despite UREGNI’s assertion that NI customers will save £50m per year as a result of the first I-SEM T-1 auction, AES has carried out its own analysis of the impact on energy costs absent Kilroot coal units. This analysis, based on both a three-year historical review assuming dispatch of the next lowest cost generators’ energy as well as forward modelling on an all-island basis, indicates that the capacity auction saving in respect of Kilroot’s coal units is far outweighed by additional energy costs paid to less efficient, more expensive units. These additional costs would materially impact consumers’ bills.
30. Formal market analysis carried out by the system operator is urgently required to assess the overall impact on whole sale energy costs for NI and all-island consumers (assessing wholesale capacity, energy and system service costs).
31. In terms of forward market liquidity AES has been a key player within the current SEM arrangements in its role as the largest Independent Power Producer on the Island.  Liquidity in the forward market time-frame is critical for suppliers being able to manage wholesale price volatility (to the benefit of customers) and also critical to allow smaller independent suppliers to manage price risk.  With the closure of the Kilroot coal units, forward market liquidity and competition is significantly eroded. Without this, there is the real risk that exit signals are being sent to plant for capacity reasons, which will prove to be the wrong signals for NI consumers when all costs are taken into account.

What bureaucratic, legal, or infrastructure obstacles remain for the construction of the North-South Interconnector?

32. AES maintains that the delivery of the North-South interconnector would be highly beneficial to the all-island market, as it would better align the island’s physical infrastructure with the already integrated financial market.  However, with delivery scheduled for late 2021/2022, the interconnector does not contribute to security of supply in any the first four T-1 auction periods (i.e. until the first T-4 auction outcome delivers) and so should not be considered a solution in the short term but more a medium-term solution.
33. Of far greater near-term significance is the change in the ability of the system operator to dispatch existing interconnectors (East-West Interconnector and Moyle Interconnector) in the progression from SEM to I-SEM. Currently, SEM market participants bid to secure physical capacity on the interconnectors and on any day the energy would flow in the direction they instructed. This can be considered as “dispatchable” plant as it can be called on when the system needs it.
34. However, under I-SEM this will change (including for the Moyle interconnector between Northern Ireland and Scotland which was contracted for 216.27 MW in the T-1 capacity auction) as market participants can no longer secure physical capacity, but instead will bid for “Financial Transmission Rights” (FTRs). FTRs do not secure the ability to flow the amount of energy a participant wants from one market to another based on security of supply needs. Instead on the day a European Market Algorithm (called “Euphemia”) will calculate the direction and volume of energy flows, based purely on the difference between prices in each market (based on bids). This means that:  
1. the direction in which the interconnector flows is decided solely on the basis of the price difference between markets (in this case GB and ISEM);
2. the direction is decided by an independent algorithm;
3. the system operator cannot overrule the commercial market and thus cannot overrule the direction of flow decided upon by the European designed algorithm.
35. AES has noted that successive Eirgrid Group Generation Capacity Statements have highlighted a security of supply issue for Northern Ireland from 2016, which would then have been exacerbated by closure of Kilroot’s coal units after 2021.  This analysis formed a critical part of defining ‘the need’ within Eirgrid/SONI’s Planning Application for the second North-South Interconnector.  Post the ISEM T-1 capacity auction results SONI has now repeatedly stated that there is no NI security of supply issue from 2018.  This seems inconsistent with their historic position and their position with respect to the need for the North-South.

How will the Republic of Ireland’s proposed energy integration with the EU, through a Celtic Interconnector or other means, affect its energy integration with Northern Ireland?

36. AES would point the Committee towards the Energy Association of Ireland (EAI), which commissioned legal opinion on the potential impacts of Brexit on the SEM, including scenarios in which Ireland does and does not achieve physical interconnection with another EU state.
37. In expectation of continued operation of Kilroot beyond 2020 (as outlined in the EirGrid Group Generation Capacity Statement 2017-2025), AES had made significant investment in planned SUFA (Secondary Under Fired Air technology) to meet EU Industrial Emissions Directive regulations from mid-2020 to 2023 with no reduction in running hours. This would have avoided cost to consumers of building new generation capacity before required, and bridged the expected Brexit transition period with EU compliant generation as new lower carbon capacity was developed. This investment is now frozen as a result of the T-1 capacity auction results.
38. The expected capacity of the Celtic Interconnector is 700MW. As the TSO operates the system in terms of safety by ensuring there is sufficient capacity to replace the largest infeed on any day, this is expected to increase the capacity reserve requirement for Ireland by 200MW from the East West Interconnector which has a capacity today of 500MW. As a result Ireland may be in a position of having an even greater degree of reserve capacity then it has today, which is already significantly greater than that for Northern Ireland.

What are the implications of the prolonged state of the collapsed Executive and NI’s pressing energy needs?

39. The continuing absence of an NI Executive has prohibited delivery of long-term policy in the form of the Programme for Government and the overdue new Strategic Energy Framework (SEF). The latter is required to guide energy investment in the near term and out to 2030, providing time-critical market guidance to ensure that near term investment in medium term life extension and new generation capacity ensures that Northern Ireland receives energy of the right quality, in the right location, at the right price, in the context of the I-SEM and the ‘Delivering a Secure, Sustainable Electricity System’ process (DS3).
40. Historically SONI has used a Loss of Load Expectation of 4.9 hours for NI as part of their overall annual security of supply assessment.  In the absence of an Executive, a decision was made by the all-island SEM Committee to harmonise Loss of Load Expectation across the Island to 8 hours, despite the fact that the second South-North Interconnector will not be commissioned until 2021/22.  It would seem that in the absence of an Executive that a key policy metric in assessing security of supply for NI has been decided by the SEM Committee.
41. Crucially, the absence of an NI Executive means that energy policy which should address the fundamental, market-driving question of how much indigenous generation Northern Ireland needs to ensure security of supply has been lacking. There is clear, recent precedent of the NI Executive fulfilling this role, materially influencing the assessment of risk to security of supply and wider economic signals. In December 2013, DETI published an information paper[6] on the need to investigate security of supply in light of the 2013 Generation Capacity Statement’s forecast that the introduction of the Industrial Emissions Directive on 1 January 2016 would reduce NI supply margin to 200 MW. Following this, in December 2014 DETI and UREGNI published a joint information paper[7] which noted that, “[t]he 200MW surplus from 2016 meets the generation security standard and therefore in normal operational situations is satisfactory. However, in the event of a prolonged outage of a large generation plant, or of the Moyle interconnector, this margin may not be sufficient. Without the second North-South interconnector, and with the Moyle interconnector operating at half capacity, Northern Ireland is dependent on three large generating units (Kilroot, Coolkeeragh and Ballylumford power stations). The removal of 510 MW from the Ballylumford plant from January 2016 together with the impairment of any other plant for a prolonged period is the risk identified by the system operator SONI.”
42. With the expected reduction of NI conventional generating units from eight to five (a 37.5% reduction) as a result of the T-1 auction results, as well as increased maintenance requirements for the remaining plant and a current lack of a proven track record of Demand Side Units, precedent would suggest that an active NI Executive would have investigated the acceptability of the proposed calculations underlying the emerging supply margin. In 2014, DETI mandated additional interventions (in the form of 250MW of competitively tendered additional supply from 2016-2018 inclusive, an upgrade to the Moyle Interconnector and a planned acceleration of the North-South Interconnector) determining that the cost of these interventions was justified as “the impacts of the security of supply risk are likely to significantly exceed the costs of addressing the problem”.
43. NI Executive also has a clear responsibility for setting expectations for fuel diversity of generation and the impact on system security for NI. Kilroot’s closure will aggressively accelerate the removal of the last coal plant from NI, moving the region to a complete dependence on pipeline natural gas for dispatchable energy. Both the Scotland Northern Ireland Pipeline (SNIP) and Scotland Ireland Pipeline (SIP) come from the same gas interconnector point in Moffat, Scotland, so both are subject to a single point of failure. From 13-30 December 2017 the failure of the Fortes Pipeline in Scotland caused GB gas prices to soar. If such an incident were to take place at Moffat, both SNIP and SIP gas supply to the island of Ireland would be interrupted at source. The Ballylumford gas units and the ESB Coolkeeragh station are required to store five days’ liquid fuel reserves on site, but this would be insufficient to withstand an incident like Fortes, and would add significantly to energy prices.
44. Mention has been made of NI relying on the South North Pipeline from Ireland to NI (SNP) for gas supplies in such a scenario. The SNP has only flowed on seven occasions, all for test purposes, and today there is currently no agreed operational or tariff regime to allow gas to flow to NI. The technical capacity of the SNP is two thirds of the SNIP and it is highly questionable with gas could be delivered to Coolkeeragh and Ballylumford Power Stations at the required volume and pressure. Further by the end of 2018 Mutual Energy, the independent gas operator in Northern Ireland, has predicted that gas demand in Northern Ireland will be at such a level at importing through the SNP will become a necessity. If this were to happen, the capacity available in SNP to replace SNIP if there were issues will be even less than two-thirds of SNIP. It is for the NI Executive to determine if this reliance on imported reserves for local security of supply is acceptable.
45. Furthermore, there is clear precedent for the devolved government to provide local policy guidance regarding air quality impacts from energy generation. The absence of an NI Executive has led to a divergence in approach to the proliferation of Medium Combustion Plant (MCP) (i.e. sub-50MW assets and largely diesel generators) between Westminster and Stormont, with a material impact on entrance signals sent to energy investors in Great Britain and Northern Ireland.
46. In response to concerns regarding air quality emissions due to a lack of planning and testing requirements, UK Government consulted on the Medium Combustion Plant Directive[8] (MCPD) throughout 2017 and passed legislation in January 2018 to ensure that MCP will be subject to permitting, environmental reporting and emissions limits for particulates, nitrous oxide and sulphur dioxide. New Demand Side Unit (DSU) market participants successful in the January 2018 BEIS Capacity Market auctions will be automatically bound by these restrictions, and existing DSU market participants will face a staggered introduction of the MCPD.
47. In comparison, the MCPD has not yet been transposed into NI law and so did not influence the introduction of 600 MWs of new DSUs/AGUs across the island (around 120 MW in Northern Ireland) indicated by the redacted T-1 auction results and explicitly mentioned by SONI General Manager Robin McCormick in his statement on the T-1 auction results[9].
48. AES’ understanding is that the MCPD will be transposed into Northern Ireland law by Northern Ireland Environment Agency as an amendment to the 2013 regulations, thereby retroactively requiring specified DSUs to meet similar emissions and environmental regulations as existing OCGTs. It is not understood the degree to which this will impact potential dispatch of the units, but OCGTs are subject to 500 hours annual running as part of the permitting process.
49. An up to date Strategic Energy Framework outlining environmental and reliability factors of generation scheduled for development in Northern Ireland could have anticipated this discrepancy between emerging environmental compliance, air quality concerns, and planned investment in new generation capacity.
50. Overall, in comparison to 2013/14, there is currently no transparency around the supply margin resulting from the T-1 auction results, nor around the assessment methodology undertaken by SONI to assess the risk to supply margin if there is “any deterioration from normal conditions” (i.e. unit unavailability) as happened in the 2014 information paper. As well as the information deficit surrounding the technical assessment carried out by SONI, the absence of the NI Executive has prevented the launch of a devolved investigation into pressing energy issues including,
1. the impact of the Kilroot coal units closure on energy costs for NI consumers (AES’ analysis indicates this will increase when higher energy cost OCGTs and Demand Side Units cover the energy deficit);
2. the risk posed by loss of generation fuel diversity and a move to a complete reliance on imported gas for conventional generation in NI;
3. an updated assessment of the December 2017 DETI/UREGNI information paper which analysed “the impacts of the security of supply risk” to the wider NI economy versus the “costs of addressing the problem”;
4. the likely impact of a proliferation of and increasing reliance upon MCP instead of mid-merit generation.
51. The failure to guarantee security of supply in the medium term is likely to discourage foreign direct investment in Northern Ireland. If Northern Ireland is perceived or demonstrated to have an unreliable energy infrastructure, this would be factored into future siting or investment decisions by investors.

23 February 2018