1. Introduction

It is an exciting time in the Irish renewable space at the moment with the first Renewable Energy Support Scheme[1] (RESS) auctions due to commence soon with a closing date for submissions of 28 July 2020.

We have been working with various wind and solar developers as they develop trading and balancing solutions for their RESS assets and one common question we are asked is “What Route to Market Structure is best for me?”.  The purpose of this Insight is to help answer this question.

Under RESS, in a manner similar to REFIT, the RESS generator is required to enter into a Power Purchase Agreement (PPA) with a licenced supply entity (Supplier).  The subsidy payment is made via the Public Service Obligation Levy (PSO) to the Supplier.

The two most common routes to market for Irish renewables over the last five years has been:

• Traditional Power Purchase Agreement
• Supplier Lite Structure

In this article we describe both structures and highlight the advantages and disadvantages of each.

2. Power Purchase Agreement

A traditional PPA is a standard agreement whereby the RESS Generator contracts with a licenced supplier (such as ElectroRoute Energy Supply Limited) under which the Supplier purchases every MWh of power produced by the Generator and in return pays the Generator a pre agreed price as shown in Figure 1.  For RESS 1, this price is likely to be the Generator’s Strike Price less an agreed Fee.

Figure 1 – Typical Power Purchase Agreement Structure

The PPA is the most straightforward, and least administratively intensive route to market for a Generator – typically the supplier will manage all market interfaces, trading, balancing, collateral, working capital and PSO cashflows and in return earns the Fee.

They key advantages and disadvantages of a Power Purchase Agreement are as follows:

3. Supplier Lite Structure

ElectroRoute estimates that approximately 40% of REFIT 2 onshore windfarm generators (over 900MW) adopted a Supplier Lite route to market. The structure became popular from 2015 onwards for a few reasons, predominantly:

• At that time the only entities offering long term PPAs were the incumbent utilities who were not providing competitive or flexible offerings,
• Generators were aware that the introduction of I-SEM would result in market change and did not want to enter into inflexible long term contracts with the utilities, and
• the emergence of ElectroRoute who pioneered the provision of services to enable bankable Supplier Lite structures.

The Supplier Lite structure is very similar to the PPA structure, with one key difference. Instead of entering into a PPA with a third party offtaker (such as ElectroRoute or a Utility), the Generator sets up its own licenced supply vehicle with which it contracts. See Figure 2 for an illustration of this.

Figure 2- Typical Standalone Supplier Lite Structure

Having its own supply vehicle (SupplyCo) allows the Generator to control its PPA and Route to Market, however, in most scenarios, a Generator will not have:

• the ability to manage the compliance requirements of owning a licenced supply entity
• the market access and trading capability to (eg SEMOpx access, clearing bank structures etc)
• 24*7 trading and forecasting capability to manage balancing risks.

Therefore usually the SupplyCo will contract with a third party trader, such as ElectroRoute, who assumes responsibility for market interfaces, forecasting, trading and balancing and pays the Day Ahead reference price to SupplyCo less a pre agreed Fee for each MWh.

PSO management and R Factor related working capital remains the responsibility of the Asset Owner.   Figure 3 provides an overview of how such a structure works.

Figure 3- Supplier Lite (sleeved through ElectroRoute)

4. ElectroRoute RESS Services

Whether an Asset Owner decides to follow the PPA or Supplier Lite structure, ElectroRoute can provide competitive, bankable solutions underpinned by credit support.

Through its solutions, ElectroRoute will, for a fixed fee per MWh,

• Take all balancing risk exposure
• Provide access to the ex-ante I-SEM markets (SEMOpx & clearing bank access)
• Manage all trading and market interface requirements
• Take responsibility for all wind/solar and price forecasting costs
• Cover all trading fees and all collateral movements with the market.

If you wish to discuss route to market options for your future RESS project, please reach out to our team at clientservices@electroroute.com.

ElectroRoute’s 24*7 trading desk

Reference

[1] https://www.dccae.gov.ie/en-ie/energy/topics/Renewable-Energy/electricity/renewable-electricity-supports/ress/Pages/default.aspx

The post Route to Market Options for RESS 1 appeared first on ElectroRoute.

What is wind dispatch down?

Due to its current status in the SEM as a price taker with priority dispatch, wind generation is typically dispatched to its availability provided it is possible to do so without compromising the secure operation of the system. However, at certain times it will be necessary to reduce the level of wind generation (dispatch down) to continue to operate the system securely. There are many reasons which could lead to wind generation being dispatched down, these reasons can broadly be divided into either constraints or curtailment events.

• Constraints – Constraints refer to events where generation is dispatched down due to localised network reasons and where only a subset of wind generators can contribute to alleviating the issue.
• Curtailment – Curtailment refers to events where generation is dispatched down due to system-wide issues and dispatching down the generation of any or all wind generators can alleviate the issue.

It is important to distinguish between constraint and curtailment events since a wind generator’s compensation for being dispatched down could vary depending on the type of event. While wind generators with firm access currently receive the market price for volumes dispatched down due to both constraint and curtailment events, from 2018 volumes dispatched down due to curtailment will no longer receive market compensation. Additionally, a wind generator supported through either the REFIT or NIROC schemes will receive these support payments based on its metered generation, i.e generation after curtailment. Curtailment therefore represents a volume risk impacting a wind generator’s revenue.

Dispatch down in recent years

Dispatch down has increased in recent years driven primarily by increases in curtailment as wind capacity continues to increase and with it the level of wind penetration. However, despite record levels of wind installation in 2016 and outages on both interconnectors throughout the year (interconnectors generally facilitate greater levels of wind generation without the need for curtailment), there was still a decrease in dispatch down levels.      

What caused the lower dispatch down levels in 2016?

There are several factors which influence dispatch down of wind but one of the most important factors is the level of available wind output across the year, in other words how much does the wind blow. The average wind load factor in 2016 was 27%, much lower than in previous years (the average of the past six years is approximately 30%). With less wind generation across the year there will generally be less times when wind needs to be curtailed for system security reasons (for example to ensure the SNSP limit isn’t breached) and consequently less dispatch down of wind.    

Future Outlook

Undoubtedly, the continually increasing levels of installed wind capacity on the system will exert upwards pressure on the levels of wind dispatch down in the coming years, potentially counteracted by further increases in the SNSP limit as EirGrid and SONI continues to move towards the targeted SNSP limit of 75% through the DS3 programme. The introduction of I-SEM next year should also help reduce wind dispatch down as implicit market coupling replaces current interconnector scheduling arrangements between the SEM and GB. Today in the SEM, interconnector flows are scheduled by interconnector users in restrictive morning trading gates, which can sometimes result in inefficient power flow and power being imported while wind is being dispatched down. In I-SEM, interconnector flows will be scheduled by market coupling algorithms which will ensure that power always flows to the more expensive market. This should result in greater exports to GB during times of high wind generation, thereby reducing the need for dispatch down of wind generation.

The post Wind Curtailment Down in 2016 Despite Increase in Installed Capacity appeared first on ElectroRoute.

  In the early hours of Monday, the 9th of December, Ireland saw the first negative EP2 System Marginal Price in 5 years as prices plummeted to -€84.96/MWh for three half hour periods. A rapid increase in wind generation, as seen in the graph below coincided with a low demand period stemming from particularly mild weather conditions for this time of the year. The full availability of both Irish interconnectors, as well as significant exports of wind to GB were still not enough to keep prices in the positive bracket as TSO actions had to be taken to ensure the stability of the system.   Keep an eye out for the next installmentof ElectroRoute Insights as we dig deeper into this event. In the early hours of Monday, the 9th of December, Ireland saw the first negative EP2 System Marginal Price in 5 years as prices plummeted to -€84.96/MWh for three half hour periods.

The post High Winds Leads to Historic Negative Prices in the SEM appeared first on ElectroRoute.

  I regularly get asked if there will be negative pricing in the I-SEM. It’s one of those phenomena of European markets that we often read about but which seems totally alien to us in the SEM. Negative pricing is when market prices clear at a value less than zero, meaning generators are willing to pay for their power to be consumed. In essence, it is an economic signal that there is a significant over-supply in the market (we’ll delve a bit more into how it happens in next week’s Insights article). So, will it happen in the I-SEM? If last Friday’s events are anything to go by, it’s certainly a possibility. On Friday 23rd September, both of the day-ahead runs of the SEM market for Saturday cleared at -€100/MWh during the 6:00-6:30 trading period.   This means that during this trading period a generator would be charged €100 for every megawatt generated and suppliers were actually paid for consuming power. The reason for this event becomes clear when we examine the view of system fundamentals that the market had on Friday. The day-ahead runs of the SEM solve using forecasts that are available at the time. You can see on the below chart that demand was quite low, as you would expect for a mild Saturday. Wind was forecasted to nearly completely meet that entire demand during the early morning period.   In addition, the 500 MW East-West Interconnector linking Ireland to GB was (and continues to be) on outage and the Moyle Interconnector’s export capacity is limited to 295 MW due to technical issues. That’s 705 MW less demand capacity on the system, which limits the amount of generation that can be scheduled and our capability to export during high-wind situations. Because the forecast wind was meeting the large majority of system demand, just over 200 MW of non-wind generation was required to meet the rest of the system demand. This remainder was largely made up of priority dispatch units such as CHP, biomass and hydro. All of these units are registered as price taking units in the SEM, meaning they cannot set the market price. This left SEMO with very few price making units which could actually set the market price. In the end it was actually a demand side unit which was the marginal in-merit unit during the 06:00-6:30 trading period and set the market price with their bid of -€100/MWh. As demonstrated in the chart above, wind outturn was below forecast, meaning additional price setting thermal generation was required to fill the gap in later market runs. As a result, the negative price in the 6:00-6:30 trading period did not persist in subsequent market runs, with the market price in the first ex-post run clearing at €22.08/MWh. While the final EP2 price that all participants are settled at will not contain negative prices due to over-forecast of wind for Saturday, it is worth thinking about how a similar situation would play out in the I-SEM. Unlike the SEM, trades in the I-SEM day-ahead market will be firm contractual positions, meaning in this scenario generators who traded in the day-ahead market would have committed to paying €100/MWh for that period. If you had waited to sell your power in the intraday market instead, updated wind forecasts would likely have seen market prices return to positive values, enabling you to get paid for your generation during the 6:00-6:30 trading period, rather than paying for it! The I-SEM will have multiple markets with firm pricing, so understanding system fundamentals (such as wind forecasts) and which market to trade in will play a key role in maximising asset value in the new market. Another useful insight from last weekend is the benefit of interconnection to the Irish market. At the day ahead stage, the Moyle Interconnector was scheduled to fully export 295 MW during the negative pricing period. If the additional 705 MW of interconnector capacity on outage was available and exporting, this additional demand would likely have prevented the negative prices from occurring. Furthermore, it is worth noting that the market schedules seen during the negative pricing period, which had nearly 100% of demand being met by wind, were unconstrained schedules and would not happen in real life. This is because EirGrid can only allow up to 55% of demand and exports to be met by wind (known as the “SNSP” limit) and must curtail wind generation when it goes above this level. Therefore, additional export capacity on the interconnector would also help mitigate the inevitable wind curtailment which would have to been carried out to bring wind generation below the 55% SNSP limit. In next week’s edition of Insights, we’ll take a closer look at the fundamentals that drive negative prices using examples from the GB market, where negative pricing events have increased significantly in recent years. Update: Market Prices have gone negative again for two trading periods in the day-ahead runs of Wednesday’s trading day. With EWIC on outage until early November, we could potentially be seeing more negative price events during periods of high-winds over the coming weeks.

The post Negative Pricing in I-SEM? It’s already happening in SEM! (Part 1) appeared first on ElectroRoute.