Written evidence from AES UK & Ireland (EEE0024)

AES Kilroot Power Limited (KPL) in the competitive Single Electricity Market (SEM) since 2010

Over the past 3 years on average K1 and K2 have run in excess of 6,400 hours they generated 86% of the time they were available.

• Essentially K1 and K2 run baseload for most of the Winter (October to March) so “surplus” is negligible.
• In the summer, each unit run as “mid-Merit” units within the economic merit stack and also dispatched to address NI system constraints.

Kilroot Units K1 & K2 running hours

It is worth noting that no generation plant in the system is used to full capacity, as even the cheaper plant are run at lower loads either to provide operational reserve or when the wind is blowing and demand is low.

Trend over last three years

In 2017, on our figures, the Kilroot Coal Units K1 and K2 supplied approx. 15% (1.32TWh) of the Total Energy Requirement (TER) for Northern Ireland (9.07 TWh).  It is worth noting that 2017 was a very windy year and there were adverse commodity movements impacting Kilroot dispatch, so we look back over the past three years to capture the trends including commodity volatility. 

• Kilroot coal units have supplied approx 20% of NI energy demand over past three years
• Each Kilroot unit has been running over 85% of the available hours per year for the last three years:
• Average of 6400hrs/year (over past three years) for each unit;
• Capacity for each coal unit is 58% (a measure of how often it has run at full capacity – OCGTs, B Station Units <5% capacity factor) – exit signal is being sent to more frequently used plant;
• As per current legislation OCGTs are classified as emergency generation and have a 500hr (stack hours) annual limit (environmental consent constraint) – 238MW of the System Operator Northern Ireland (SONI) procured capacity cannot run beyond this running hour restriction

Running hours 2015, 2016 and 2017

As mentioned above 2017 was a high wind generation year, and in which commodity prices moved significantly negatively impacting Kilroot coal units. Due to this the running hours for Kilroot Coal units were less than previous years as outlined in the table below.

This year’s running hours from 1st Jan 2018 to 22nd March 2018

• K1 has been online for 91% of the YTD
• K2 has been online for 67% of the YTD (10 days Forced Outage in March)
• 1 Unit Rule at 1400MWs has been met 97% of the time
• 2 Unit Rule at 1550MWs has been met 76% of the time

• This means that Kilroot Coal units have operated, in all conditions, while the wind has been blowing and when there has been no wind.
• From 5th to 21st January 2018 at least one Kilroot unit was dispatched 100% of the time that NI demand exceeded 1,400MW (consistent with a previous System Constraint rule for NI which was removed in January 2018 by SONI).

Kilroot’s generation and revenue profile

Essentially K1 and K2 run baseload for most of the Winter (October to March) so “surplus” is negligible. In the summer, each unit run as “mid-Merit” units within the economic merit stack and are also dispatched to address NI system constraints.

Any assessment of generator profitability should include an understanding of the risks borne by a Generation Licensee within the market and regulatory conditions

Whilst capacity payments are not intended to cover all fixed costs of all generator classes, the predictability and relative certainty of the payments are vital to ensure many generators are financially viable. We do not view regulatory approved capacity payments as a ‘nice little earner’.

Our profit margin has been steadily eroding since 2013 on the back of commodity and market pressures.  The challenges of the market and a significant impairment in 2015 have meant AES Kilroot Power Limited has not paid a dividend to the AES Corporation since 2013. However, we have continued to invest significantly in new technology (such as Energy Storage) on a merchant basis and to invest to comply with environmental legislation to ensure extended life of the assets. 

We would draw your attention to the most recent Regulator Commissioned “Generator Financial Performance in the Single Electricity Market (SEM)” Report published in November 2016 by Cambridge Economics that showed

• Key finding 1: Higher profit margins earned by generation fuel sources with relatively small share of the market. As in previous years, gas represented the dominant fuel source for electricity generation. However, the largest net profit margins are earned by Hydro, Pump Storage and Distillate & Oil plants which represent a very small proportion of total electricity generated and total revenues earned
• Key finding 2: Mid-Merit plants provided around half of the electricity generated in the SEM in both 2014 and 2015, but have the lowest reported profit margins. This category includes coal plants such as Kilroot which generally report lower profit margins.

Northern Ireland is operating only a limited PPA market: under a PPA you have a lower cost of capital – higher operational risk but lower commercial risk. Today, and since 2010, we have operational risk plus commodity risk, which is exacerbated by the lack of liquidity in the market and the less manageable volatility in the market.

The last PPA in Northern Ireland is between Viridian’s Power NI Power Procurement Business (PPB) and the AES Ballylumford C Station.  In 2015, the Utility Regulator had the opportunity to terminate this PPA, but instead determined that at the point of evaluation the contract remained in the interest of consumers. The Utility Regulator can terminate this PPA with six months’ notice, and given their on the record comments in relation to PPAs it is surprising that the termination powers have not been exercised.

Innovation and investment at Kilroot

AES has a long history of innovation globally and locally. As well as continued environmental and efficiency investments, AES Kilroot Power Ltd tested the potential for the co-firing of wood pellets in the early 2000s before many other generators had started to explore biomass opportunities.

While this particular approach was not sustainable at Kilroot, AES Kilroot Power Ltd has invested in deploying world leading low emissions technology at the site. Since 5 January 2016, the Advancion Array has been operating as a fully commercial project within the system operator’s existing Harmonised Ancillary Services system, without any form of customer subsidy.  The array provides 10 MW of interconnected energy storage, equivalent to 20 MW of flexible resource.

It is a complete, battery-based alternative to traditional peaking power plants and pumped hydroelectric storage projects that provides a dependable, smart and cost-competitive means to support a reliable, low carbon electricity system for the Northern Ireland economy.

Additionally, Innovate UK provided Energy Catalyst funding for Queen’s University Belfast to investigate the full potential of energy storage to benefit the UK and Ireland electricity systems by analysing the impact of this array.

Other planned innovation included significant investment in SUFA (Secondary Under Fired Air technology) to provide emissions compliant generation 2020-2023 with no reduction in running hours and avoided cost to consumers of new generation before required. The Utility Regulator disallowed recovery of this investment during the USPC process.

The bid process

In relation to assertions that ‘a lot of the decisions about what AES has done were not taken by Ian Luney and his team at Kilroot”.  This assertion is baseless and without any foundation.  The Directors of AES Kilroot Power Ltd have obligations with respect to Financial, HS&E, Company and Energy legislation and the business is managed at a local level within the Northern Ireland energy market.  Furthermore, it is the local Directors who carry all liability associated with complying with our Licence and other contractual obligations. 

In relation to being able to “plan for not securing capacity payments” we would re-emphasise the point the each of the Kilroot coal units had statutory maintenance periods through the 2018/19 period which were required to ensure that the units could run.  If this work was not undertaken then the units would not be in a position to operate. 

AES Kilroot Power Ltd bid price for the coal units was subject to regulatory oversight by the Utility Regulator (UR) and its consultants in line with the prescribed auction process rules and did not include any buffer for margin or risk contingency:

1. KPL transparently deducted forecast energy and ancillary services revenues from the total running costs of the station.
2. KPL was obliged to include in the bid price statutory planned maintenance work on both of its units brought about by the significant running of the Kilroot coal units in recent years.
3. The Capacity Market Rules and more specifically those associated with the Unit Specific Price Cap process managed by the Utility Regulatory explicitly stated that Net Going Forward Costs could only be recovered in the Capacity Period during which they were incurred.  This prohibits the smearing of costs and participants doing so would not be able to recover costs incurred in previous years. 
4. No prudent or commercially rational operator would defer the recovery of such substantial multi-million costs into periods in which they had no certainty of recovering them, given the annual nature of the T-1 capacity auctions

The capacity revenue for the Ballylumford 536 MW CCGT was awarded to Viridian Group’s Power NI PPB business who bid this into the capacity market auction, not AES.

The derogation process

Much has been made of this by the regulator and the system operator but this would have required KPL to apply for a binding derogation for a new market that hadn’t been developed yet based on figures and costs that no one could predict.

Every Generator without a derogation in place had a mandatory obligation to bid into the first T-1 Capacity Auction.

In order to comply with the 36-month notice period, it would have been necessary for AES to apply for the binding derogation in May 2015. This is 6 months in advance of the 36-month rule being added to the Grid Code, in order to ensure it could opt out of the Capacity Auction.

While the broad principles and parameters of the market were outlined by the regulatory authorities, very little was known of the details, rules, tariffs and timelines for each pf the three markets of Energy, Capacity and DS3, and indeed much still remains unclear (as the regulator alluded to) and subject to change.

This is reflected in the most recent delay to DS3 Volume Capped Auction for High Availability Units, which is the part of the market the AES Kilroot Advancion® Energy Storage Array is expected to operate in. When AES last gave evidence to the Select Committee the DS3 market was set to come into effect in late 2016/early 2017.

In any event the 36-month Grid Code notice obligation has been contentious from the outset.  AES Kilroot Power Ltd, AES Ballylumford Ltd and other Generator Participants including ESB objected to this Grid Code modification in Northern Ireland as it was inconsistent with the proposed T-1 capacity auctions.  Generator’s tabled an NI Grid Code modification in relation to the 36month notice period but neither SONI nor the Utility Regulator took any action to address these concerns. 

In addition, the issue was raised multiple times at Regulatory ISEM Senior Stakeholder Meetings and whilst the issue was acknowledged it was never addressed.  In the CRU paper Regulatory Approach to Maintaining Local Security of Supply in Electricity it is acknowledged that the 36month Grid Code notice obligation could cause issues with the results of annual T-1 Capacity Auctions and a process was put in place to provide clarity on how this could be addressed with an explicit acceptance that Licencee’s had to be able to finance their activities during the transition period to the first T-4 delivery date (2022/2023).

The UR has produced no similar paper and for the avoidance of doubt KPL are of the view that no Licencee can be obliged to operate for 36-months if it is not financially or economically viable to do so.

Material Changes in the Market

As well as changes to the auction timelines, there were two material changes in the market:

1. Change to the Loss of Load Expectation (LOLE) metric for Northern Ireland resulting in a much lower auction Capacity Requirement for Northern Ireland. The existing security standard for Northern Ireland was set at 4.9 hours and this was set aside in favour of a more relaxed LOLE of 8.0 hours.  Our understanding from EirGrid’s most recent Generation Capacity Statement is that the LOLE metrics were only supposed to be harmonised when the second North-South interconnector was commissioned in 2021/22.
2. Operational Constraints Update: Until January 2018 SONI themselves said that two Kilroot units were needed – see the timeline below:

•         15th December 2017 SONI Operational Constraint Document published continues to include operational constraint for one Kilroot Unit to be run if NI demand was above 1,400MW and two Kilroot Units to run if demand was above 1,550MW.

•         15th December 2017 - T-1 Capacity Auction closed

•         18th December 2017 – RoI Regulatory Authority (RA) published paper on Regulatory Approach to Maintaining Security of Supply in Electricity (there is no equivalent document for NI)

•         20th December 2017 - provisional auction results issued to AES

•         20th December 2017 - EirGrid/SONI (the TSOs) jointly published a Generation Plant Closure Process document

•         12th January 2018 - SONI (NI TSO) provide to UREGNI (NI RA) requested assessment of capacity and NI system stability based on provisional T-1 auction results for May 2018 to September 2019 period

•         19th January 2018 - SONI issues revised Operational Constraints Update which removes the previous October 2017 Updates reference to requiring one or two Kilroot coal unit(s) when demand in Northern Ireland exceeds 1,400MW and 1,550MW respectively

•         25th January 2018 - final T-1 capacity auction results confirmed

•         13th December 2018 - subject to 6 months’ notice, the second T-1 auction will take place, for period Oct 19 to Sep 2020

•          March 2019 - Subject to almost a year’s advance notice, the first T-4 capacity auction will take place, for the period Oct 2022 to Sept 2023

Claim this shows competition working

The outcome of the auction

• Dilutes the position of largest and most innovative independent power producer on the Island;
• Reduces all island competition as we see vertically integrated companies, in particular those with large plant portfolios, increase market position – EU 3rd package was about separating vertically integrated utilities across Europe to drive competition.
• Significantly dilutes liquidity in the forward market as the KPL coal units will not be offering any volume and this erodes supplier’s ability to hedge forward price prices and offer more certainty to their customers.

Interconnectors

In the SEM market from 2007 to date:

• Interconnectors were not paid availability payments (otherwise known as “capacity payments”) as they did not generate energy, they simply moved energy.
• In SEM to use Interconnectors auctions were held where market participants bid to secure physical capacity on the Moyle interconnector for one or more years in the future.

• On any day, such market participant with booked interconnector capacity wanted to either export or import energy, it would simply make a nomination on the Moyle and energy would flow the direction instructed, thereby utilising the capacity the participant had booked.

In the I-SEM Market much is expected to change

• Firstly, the Moyle Interconnector was allowed to participate in the first T-1 capacity auction for the new ISEM market, and successfully secured a capacity contract totalling £8.2m.

• Secondly, from May 2018, participants can only participate in auctions to secure financial rights rather than physical capacity on the Moyle interconnector (termed “Financial Transmission Rights” or “FTRs”). This does not secure the ability to flow energy in the direction you want.

• Instead on the day a European market Algorithm (called “Euphemia”) will dictate the direction and volume of energy flows, based purely on the difference between prices in each market (based on bids).

• If the participant has secured an FTR is the correct direction it receives the economic value equal to the difference between the two market prices (nett of the cost of the FTR).

• The design of the ISEM market limited the capacity Interconnectors can bid into the capacity market auction to 60%. However simplistic approach assumes incorrectly that on any day 60% of Moyle is available to deliver power to ISEM. There is in fact no guarantee of this given

• 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), and
• the direction is decided by an independent algorithm.
• The TSO cannot overrule the commercial market and thus cannot overrule the direction of flow decided upon by the European designed algorithm.

• The previous bullet point links to a very important issue for the ISEM market related to how the market has determined the Moyle Interconnector as “dispatchable”. (i.e. can be controlled to deliver energy when needed) when for the reasons outlined above it is clearly not. Thus, Moyle cannot be relied upon for Security of Supply.)

• In truth the Moyle interconnector receive these capacity payments as a “retainer” for it to be “available” to deliver energy to the NI System when it is needed, but the reality is that there is no guarantee Moyle will deliver this energy, and if the interconnector does not deliver the energy, there is very likely no penalties that will be applied on Moyle (less onerous penalties on Interconnectors than generators) for not delivering the energy when it was needed.  AES along with other members of Energy UK are currently expressing concerns about the treatment of electricity Interconnector impacts in the GB Energy Market to the Department for Business, Energy & Industrial Strategy. 

Not all megawatts are the same

• K1 and K2 bring fuel diversity and a wholesale price hedge against dependency on gas and gas price volatility. It is worth noting that the North Sea Fortes pipeline failed between 13th and 30th December 2017 causing GB gas prices to soar. More recently, the ‘Beast from the East’ weather system caused EU, UK and Irish gas prices to escalate for a prolonged period of time pushing wholesale energy prices much higher – the presence of Kilroot coal units dampened the effect of this impact and without these units the wholesale energy costs would have been even higher.
• Many of the Demand Side Unit (DSU) sites are not generation, so they do not actually provide any energy to the system as they have no, or very limited, on-site generation. What these units are supposed to do is stop a production process so as to reduce their electricity consumption (reduce electricity system load) which is similar but not the same thing as generation e.g. for frequency response, reactive power provision, etc. As in SEM there was no mechanism for penalties to be applied for non-performance of DSU units, these units have never been tested in a real operational regime, having only ever been tested with advance warning. Hence the performance of DSU units in Integrated Single Energy Market (ISEM) is not, and cannot be, known.
• Average capacity factor for each Kilroot coal unit is above c. 55% (a measure of how often it has ran at full capacity). DSUs are designed as back up with lower capacity factor of less than 1%.
• Increased dispatch of DSU units will have material impact on energy prices for NI consumers as capacity payments don’t cover actual energy generation costs.22nd January 2018 - Defra legislation enacted to restrict previously unregulated diesel generators in GB Capacity Market through Medium Combustion Plant Directive in response to air pollution concerns. It is worth noting that demand side generators will be subject to permitting, environmental reporting and emissions limits for particulates, nitrous oxide and sulphur dioxideWhile ownership of diesel generators is available on GB Capacity Market register it is not in Northern Ireland.

Orderly and fair transition

We would draw your attention to the article by Professor John Barry about the result of the Capacity Auction entitled “Closure of Kilroot – or how NOT to manage a ‘just transition’ to a low carbon energy economy”, where he states

“Energy transitions are decade long processes that need to be manged, mapped and based on clarity, openness and transparency.  The shift from one energy system to another is not as simply as switching from one fuel or source to another.” 

He asserts that the outworking of the auction undermines ability of an energy company to deliver a fair and orderly closure of a coal plant replacing it with no and low emissions technology.

Will NI be reduced to more of the same old-style CCGT gas plants, continuing our ‘carbon lock-in?

Northern Ireland as a constrained area

It is AES’ understanding that Northern Ireland in its entirety is deemed a “constrained area” by the CRM rules.

Coal Plant Closures

Unlike the coal units at Kilroot, Eggborough is not subjected to the 36-month derogation notice period and can close in an orderly fashion.

16 April 2018