In Tuesday’s blog, we celebrated the birthday of I-SEM by taking a look at the 365 days (or 8,760 hours, or 17,520 half hours, or 105,120 5-minute periods) of prices experienced in the electricity industry. In this blog, we take a look at how the new I-SEM market has performed compared with the well-matured market in GB. We also take a look at how much has changed since SEM by comparing the final year of SEM prices with the new I-SEM prices.

I-SEM Prices vs GB Prices

BETTA (the GB electricity market) has been trading energy using Day-Ahead, Intra-Day and Balancing Markets since 2005. Although it has gone through some Balancing & Settlement Code changes, it is still quite a mature market with pretty consistent and stable energy prices.

In the graph below, we illustrate the distribution of Day-Ahead and Imbalance Prices in I-SEM and GB over the past year (October 2018 to September 2019). GB Prices have been converted to €/MWh using historic daily FX rates sourced from APX.

Average GB Day-Ahead prices were €55.00/MWh which is €1.84/MWh less than average Irish Day-Ahead prices (€56.84/MWh). Average Imbalance prices in GB were €53.87/MWh, which is €0.53/MWh higher than Irish Imbalance prices (€53.34/MWh). The price spread (Day-Ahead – Imbalance price) in GB is €1.11/MWh (or £1.01/MWh equivalent) compared to €3.73/MWh in I-SEM.

In terms of volatility, the GB market produced more stable prices than the Irish market with standard deviations of €16.63/MWh in Day-Ahead and €27.52/MWh in Imbalance, compared to the Irish equivalents of €26.71/MWh and €68.91/MWh. To be fair though, the GB market is far more mature than the I-SEM market, with much larger fleet of baseload units and a smaller proportion of variable generation so you’d expect this to be the case. But hey, although our prices are more volatile, at least we didn’t have a black out!

It’s no surprise that I-SEM market participants were exposed to large volatility and unknowns in the opening months of I-SEM (it probably didn’t help that it started on the first day of the week, first day of a quarter, and first day of Winter!), however things have settled down quite substantially as shown in the results of the first 6 months versus second 6 months of I-SEM in part 1 of this series. Therefore, the above comparison with GB may actually no longer be a true reflection of market differences.

How about if we look at the last 6 months of I-SEM and GB prices? There are much more similarities between I-SEM and GB if you look at the distribution below. Although the tails of Irish price distributions are still larger than GB price distributions, it has become more closely aligned in the last 6 months.

I-SEM Prices vs SEM Prices

Naturally you’d expect a new market to present some level of variability compared to an old, well-settled market such as SEM. Actually, we’ve found there hasn’t been much difference at all! In fact, average Day-Ahead prices in I-SEM were lower than average SMP prices in the previous year by €1.70/MWh. The table below shows the average, minimum and maximum prices as well as the standard deviation over the last three Oct-Sep periods. If anything, the first year of I-SEM looks a little like the status quo for price movements. It has the highest standard deviation, but not by much. All in all, there doesn’t seem to be much difference between baseload prices in I-SEM compared to the old SEM world.

Another observation worth pointing out is that although this last year has produced similar prices as the final SEM year (2017/18), why are they so alike if underlying gas prices have fallen so significantly? We’ve stacked up the building blocks of electricity prices below using the Clean Spark Spread formula:

Where Gas is NBP prices (p/th) converted to €/MWh; ER is the Efficiency Rate of a typical Gas CCGT (which we assume to be 49%); and CO₂ is assumed to be the December EUA futures price in €/tonne converted to €/MWh using a carbon emission intensity factor of 0.375.

Looking at the graph below, all things remaining equal, the electricity price should have reduced in the last 12 months versus the previous 12 months based on the changes to gas and carbon prices. While electricity prices have reduced, they did not decrease at the same rate that gas fell (even if you take the rising carbon prices into account), so why might this be true? For one, generator bids in the Day-Ahead market are no longer restricted to the rules of the Bidding Code of Practice, so could this be a re-adjustment to the clean spark spread values? The clean spark spread seen in this year’s prices is very similar to spark spreads seen in 2016/17 of approximately €5/MWh, so perhaps this is simply the status quo. In any outcome, it’s probably too early to make any hard conclusions about the I-SEM market fundamentals, so maybe best to wait at least until its second birthday before doing anything.

Here at ElectroRoute, we offer products to clients that remove the risks of these price spikes and large standard deviations.

If you find this series interesting and would like to find out more about what we offer at ElectroRoute, please get in touch anytime with our Client Services team at clientservices@electroroute.com.

The post Happy Birthday I-SEM – Part 2 appeared first on ElectroRoute.

Tea and cake in the kitchen this afternoon everyone, it’s I-SEM’s birthday! It’s hard to believe it has already been one whole year of the new market design and look how much it has grown! It has been very interesting to look back on the past year to see what has happened in the new market, whether it is working or not, and how it compares to the old SEM world as well as our GB neighbours.

This week we’re bringing you a two-part series of what we have seen in the first year of I-SEM and how it has compared to other markets as well as the old SEM world.

The Headlines

First up is the headline stats. Here’s what a year of I-SEM prices looks like.

Average and Standard Deviation

Average Day-Ahead Prices were €56.84/MWh and average Imbalance Prices were €53.34/MWh. The average Day-Ahead to Imbalance Price Spread (on a half-hourly basis) was €3.73/MWh. While Imbalance prices on average were lower than Day-Ahead prices, the price swings were much more volatile, with standard deviations of €68.91/MWh in the Balancing Market vs €26.71/MWh in the Day-Ahead Market.

Highs and Lows

Day-Ahead prices dropped to as low as -€10.29/MWh (05:00 17.02.2019) during the night when demand was super low showing what some power plants are willing to pay the system just to stay on. On the flip side, when demand was high (and wind is low), Day-Ahead prices peaked at €365.04/MWh (17:00 02.01.2019).

The Imbalance Price is on a different level altogether. In the last year we have seen prices as low as -€281.16/MWh (even lower if you look at 5-minute periods) when the system is long. We’ve also seen prices rise to €3,773.69/MWh, which occurred on 24^th January 2019 due to unplanned outages in Northern Ireland combined with an exporting Moyle interconnector and a maxed-out North-South tie line. Read more about that event at one of our earlier blogs here.

Negative Prices and Price Spikes

Day-ahead prices were negative for 56 hours during the last year, 0.6% of the time. Imbalance prices were negative for 809 half hour periods, 4.6% of the time. Imbalance prices also exceeded the capacity market strike price of €500/MWh on 9 occasions during the past year. Any generator unit with a capacity contract were obliged at this time to pay the system back the differential between the energy price and the €500/MWh strike price, regardless of whether or not they received that energy price in the first place.

Prices by Hour of the Day

Average Day-Ahead and Imbalance prices on an hourly basis follow the typical hourly demand profile with peaks between 08:00-10:00 and 16:00-18:00. The standard deviation of Day-Ahead prices is highest at the 16:00-18:00 peak period. Imbalance price standard deviations are less consistent, with an extreme peak occurring during the 13:00 period. This is heavily influenced by the price spike that occurred on 24^th January 2019. If you were to remove that price spike from the data set, the standard deviation at 13:00 almost halves from €164/MWh to €89/MWh.

Prices by Month

Average Day-Ahead prices during Winter were approximately €67/MWh compared to €47/MWh in Summer. Average Imbalance prices were approximately €63.50/MWh in Winter and €43/MWh in Summer. There is a seasonal pattern developing in the Day-Ahead standard deviations in the right-hand side graph below as it dips during the Summer months. Already we’re seeing it picking up again for the Winter 2019 period. It is difficult to see a trend in the Standard Deviation of Imbalance prices at the moment. For now, it seems to be getting less and less, however it is expected to increase again in the next Winter period but perhaps not as high as the opening I-SEM months.

Day-Ahead vs Intra-Day Markets

I’m conscious the above was focussed on Day-Ahead and the Balancing Market only, but in reality, there is some trading activity in the Intra-Day Markets. 93% of ex-ante trades were made in the Day-Ahead market. The remaining 7% was spread across the three intra-day markets, with 3% in IDA1, 2.5% in IDA2 and 1.5% in IDA3. The graph below shows the ex-ante traded volumes per market.

The table below summarises the price statistics of each ex-ante market. The average price increases as the market moves towards real-time.

Anyway, don’t forget that cake!

Make sure to keep an eye out for tomorrow’s post where we look at how this past year of I-SEM prices compare to our GB neighbours as well as the last year of SEM.

Here at ElectroRoute, we offer products to clients that remove the risks of these price spikes and large standard deviations. If you find this series interesting and would like to find out more about what we offer at ElectroRoute, please get in touch anytime with our Client Services team at clientservices@electroroute.com.

The post Happy Birthday I-SEM – Part 1 appeared first on ElectroRoute.

As featured on the Irish Wind Energy Associations website

Trading in the Electricity Market

In Ireland electricity is bought and sold on the Integrated Single Electricity Market (I-SEM). This was launched on 1 October 2018 and brings the Irish electricity market in line with the rest of Europe. In I-SEM auctions takes place daily where generators compete to supply electricity in hourly blocks.

I-SEM is really made up of three different markets. There are two ‘ex ante’ markets – called the Day Ahead and the Intraday – which means electricity is bought and sold before the market closes. And there is a third, called the Balancing Market, which takes place after trading has ceased.

It can best be explained using an example. Let’s say EirGrid, the market operator, expects to need 4,000 MW of electricity at 3pm next Tuesday. Before Tuesday different generators will offer their electricity at prices they hope are competitive in the amounts they think they can deliver.

They are selling this electricity to suppliers – the companies that sell electricity to your family or business. This is the Day-Ahead Market and it closes 24 hours before 3pm on the Tuesday.

As we get closer and closer to the time the power is needed more accurate information may be available to generators. Maybe they won’t be able to deliver as much electricity as they had hoped. Or maybe they can deliver more.

They can adjust their position in the Intraday Market (IDM). However, when this market closes, an hour before 3pm on Tuesday, they are locked into the price they have offered for the power they say they can deliver.

If the generator does not deliver what they agreed the difference between what is actually delivered and what they promised to deliver is sorted out in the Balancing Market (BM).

In other words, if a generator agreed to deliver 100 MW of power to a supplier but is now only able to provide 95 MW, they need to buy the difference on the Balancing Market to meet their commitment.

The Balancing Market is more volatile than the Day-Ahead Market. As can be seen in Graph 1, which sets out the prices seen in the BM for each half hour since 1 October 2018, the Balancing Market prices can quickly fluctuate from very high prices to very low prices.

On 24 January, the Balancing Market Price even went as high as €3,774/MWh, when the average wholesale price for electricity in Ireland is around €60. This meant that generators which under-delivered i.e. which were “short” during that trading period were forced to buy back at €3,774 for each MW they were short. This volatility and price uncertainty presents a balancing risk for market participants.

Negative Prices

The new market has experienced a considerable amount of negative prices. Negative prices are an interesting phenomenon. These occur when market prices clear at a value less than zero, meaning generators are willing to pay for their power to be consumed.

This can seem confusing to people. Why would you pay people to buy your electricity?

But there are some large generators that incur a cost when they reduce their generation below a certain point. It can, depending on the market, be cheaper for them to sell their electricity at a loss and keep going than it is to power down only to power up later. This creates a situation where the market price is less than zero.

Interestingly, approximately 4 per cent of all half hour periods were negative. Note that negative prices are often seen in power markets across Northern Europe. It is an economic signal that there is a significant over-supply in the market.

Graph 2 below illustrates the average half hourly price in each market since the 1 October 2018. The morning and evening demand peaks correlate with higher prices on average as can be seen in the two peaks at 9am and 6:30pm.

Wind Trading

Wind farms use wind forecasts to predict their generation volumes for the Day Ahead Market and will establish positions based on those, altering their ex-ante position in the Intraday Market when they receive new wind forecasts closer to the trading period.

Considering the risk, a good wind forecast is crucial for trading wind energy. Wind is a price taker in the Balancing Market. This is because wind energy – because it doesn’t need to pay for fuel like coal or gas and has the benefit of the support scheme – bids into the market with a price of zero. This drives downward pressure on the price of wholesale electricity prices.

Generation from wind units is prioritised over other generation sources – fossil fuels for example. So, in times of high generation and low demand, when the System Operator (SO) might need to turn generators down or off to prevent overgeneration and grid pressures, wind will be turned down/off only after non-priority units have been.

Overall, wind units put downward pressure on wholesale electricity prices by displacing expensive electricity sources such as gas/coal-fired power stations along with other benefits such as a reduction in capacity market costs and avoidance of EU compliance costs as outlined in a recent Baringa publication.

The Future of Wind in the Irish Electricity Market

Ireland has had huge success installing new wind capacity on the island over the last decade. There is significant optimism that the upcoming Renewable Electricity Subsidy Scheme (RESS) auctions will usher in the next wave of onshore wind and facilitate the delivery of offshore wind in the Irish sea.

As previously mentioned, wind has put downward pressure on wholesale electricity prices and the prospect of more installed capacity is exciting from an electricity market perspective.

***About IWEA***

The Irish Wind Energy Association (IWEA) is the representative body for the Irish wind industry, working to promote wind energy as an essential, economical and environmentally friendly part of the country’s low-carbon energy future.

IWEA are Ireland’s largest renewable energy organisation with more than 150 members who have come together to plan, build, operate and support the development of the country’s chief renewable energy resource.

IWEA are an all-Ireland body, working in Northern Ireland through a partnership with our colleagues in RenewableUK.

IWEA create jobs, invest in communities, reduce our CO2 emissions and work to end Ireland’s reliance on foreign fossil fuels.

IWEA are leaders in Ireland’s fight against climate change.

For more information, please visit IWEA.

The post How Ireland’s Electricity is Traded appeared first on ElectroRoute.

The First 150 days of I-SEM; Part 2

Negative Prices

Negative power prices are a relatively common feature of power markets across Europe, particularly in regions with high penetrations of renewables. In the first 150 days of I-SEM there have been several occurrences of zero or negative prices in many market timeframes, particularly in the Balancing Market. In this, the second of our Insights in our “150 days of I-SEM” series, we assess the drivers behind negative prices and discuss one of the key questions that arises from these events: Is the presence of negative prices an unwanted feature of the new market or a long overdue market signal for more flexibility?

A QUICK LOOK AT THE NUMBERS

Let’s start by looking at prices across all market timeframes. The table below shows summary price statistics for the first 150 days of I-SEM.   There are two striking features relevant to this topic in the data above:

1. All market timeframes have experienced negative prices.
2. The Balancing Market is by far the most volatile.

Delving deeper into the Balancing Market, the figures below show the high frequency and magnitude of these events:

• of negative price 30-minute periods in the BM:      470
• Proportion of negative price periods in the BM:          7%
• Average BM Price when below 0 €/MWh:               – 50.55 €/MWh

BALANCING MARKET NEGATIVE PRICING

At a high level, negative prices are seen in a ‘Long’ system whereby high levels of supply exceed demand and system operators take actions to either increase demand or reduce generation. I-SEM began on October 1^st 2018, the beginning of the winter season in electricity markets. Even in this winter period, where consumer demand is higher, the market has experienced a relatively high frequency of negative prices in comparison to its European counterparts.   In its simplest form, a negative price occurs in the balancing market when the TSO takes an expensive downward action from a participant and that action feeds through to the pricing algorithm. However, to understand it fully we need to determine why that action was taken in the first place:

• Firstly, the system is usually long in these periods. This can be caused by participants underselling generation or overbuying demand in Ex-Ante timeframes. This could be reflective of forecast error, or in some cases may be down to trading behaviour of some participants.
• Secondly, since balancing actions are taken on a least cost basis, the system operator would choose an expensive (i.e. negative) bid from a participant for an energy action if other cheaper actions were unavailable or had already been taken.

EXAMPLE EVENT: WEEKEND OF 17^TH-18^TH FEBRUARY 2019

A useful example of such events is the weekend of the 17^th and 18^th of February. On these dates the East West Interconnector (EWIC) had a planned outage and high wind was forecasted. Day Ahead Market (DAM) prices cleared significantly below 0 €/MWh. While zero prices in DAM have been witnessed throughout I-SEM, the addition of the EWIC outage led to the lowest average daily baseload price in the DAM to date of 29.69 €/MWh and the lowest DA hour block price of -10.29 €/MWh. While this specific price was set by an Assetless Unit, a number of conventional thermal units also bid at a price even lower to ensure that they remained online overnight. The graphs below show how the weekend unfolded:   Summary of the period:

1. Wind forecast was very high for  Saturday 17^th and the first half of Sunday 18^th (see the purple line in the first graphic).
2. A significant amount of wind was dispatched down across this period, particularly on the 17^th(see the delta between the yellow and green shaded areas in the first graphic).
3. The System NIV (negative = ‘Long’) was up to 600 MW oversupplied across many periods (shown in the second graphic).
4. Day Ahead prices cleared negative as generators sought to ensure that they stayed on overnight and weren’t exposed to potentially very negative balancing prices (see the red line in the third graphic).
5. For most of the morning of the 17^th the imbalance price was set at 0 €/MWh with dispatch-down wind accepted bids feeding through unflagged to the balancing price algorithm (see the blue line in the third graphic).
6. The following night, imbalance prices dropped as low as -139.44 €/MWh when unflagged expensive actions fed through to the balancing algorithm.
7. In the period in question the following unit types had negative bids accepted in the balancing market:

• 1 biomass unit
• 2 waste to energy units
• 1 coal unit
• 1 CHP unit
• 2 DSU units.

NEGATIVE PRICING: A POSITIVE FOR FLEXIBILITY?

Generally, negative price periods occur during periods of high wind penetration when the number of dispatchable generators on the system is very low and those that remain online are near their minimum stable generation limit and need to be kept online for system security reasons. In the old market (SEM), while there were some instances of negative prices, the single ex-post cash-out price and smearing of certain cost components (known as ‘uplift’) across the trading day prevented many trading period prices from dropping below zero. In reality, the limited flexibility of the system in high wind periods always existed and the system dispatch isn’t too dissimilar to pre I-SEM profiles. With the introduction of I-SEM, there is now a real time price signal that exposes the true lack of flexibility during high wind periods. Are these events significant enough to incentivise the development of more flexible means of generation and demand-side participation? In a similar vein, the market eagerly awaits the development of the DS3 market and hopes that this provides an adequate incentive to encourage flexibility from the existing portfolio on the island, and perhaps more pertinently, provides a signal for investment in new, flexible assets to support the market and perhaps mitigate the instance or severity of negative pricing. What is for sure, however, is that negative prices have rapidly become a key feature of the I-SEM thus far. The onus is therefore now on the market, irrespective of the success or otherwise of the DS3 market, to adapt and take a solutions focused attitude to mitigating this risk to their bottom line.   If you would like to discuss how you can mitigate price risk for your asset, please contact the Client Services Team in ElectroRoute to understand your options.

The post The First 150 days of I-SEM; Part 2 – Negative Prices appeared first on ElectroRoute.

Snow and Wind No-Show: 3rd March 2019

The week of February 25^th to March 3^rd 2019 has been a weather rollercoaster on the island of Ireland. On Tuesday, February 26^th, afternoon temperatures reached 17^oC. Five days later, on Sunday 3^rd March, many areas in the southern half of the island were covered in snow. While for many people the memory of the weather on that Sunday afternoon will be of heavy rain turning to snow as temperatures dropped through the afternoon, some of us involved in the electricity market may remember it for something that didn’t show up…wind. The sixth winter storm this season, Storm Freya, tracked towards the Irish Sea and Britain from the south. On the western edge of this storm, a band of heavy rain moved northwards across the island of Ireland. At the southern edge of this band of rain there was much colder air. Just before 11am Met Eireann released a snow/ice warning for most of the country when updated forecasts predicting the southern edge of this weather system to fall as snow.

 Source: MET Eireann

 The effect that this weather pattern had on the electricity system was significant. Afternoon demand was about 300 MW higher than the previous Sunday, due to lower temperatures, however the difference in out-turn wind compared to the forecast produced on the previous day was a much bigger influence in the trading and dispatch of the system on that day.   On the previous day, Saturday 2^nd, participants submitted their bids and offers into the Day Ahead Market (DAM) for delivery the following day. Aggregate wind forecasts across the island were relatively high, particularly for the second half of the trading day. The publicly available wind forecast, published by Eirgrid, on the morning of March 2^nd predicted wind output would peak at 3.4 GW at 8pm on March 3^rd. This was driven by the prediction that once the band of rain/snow moved across the island, high winds would follow, and the significant amount of wind capacity installed in Cork and Kerry would begin to produce high levels of electricity in the early afternoon and more wind farms across the island would follow as the weather front tracked northwards. This didn’t happen. For much of the afternoon about one third of the Day Ahead forecast showed up. The chart below shows a breakdown of wind, imbalance volume and market prices for the Trading Day of March 3^rd.

Figure 1: Wind, Net Imbalance Volume (positive = “short” system) Market Prices

 The forecast at the Day Ahead stage is prime driver of the I-SEM market, with approximately 90% of volumes traded typically go through that auction and many wind traders would have sold high levels of forecasted wind for the afternoon of Sunday 3^rd March at this stage. There is typically lower liquidity in subsequent market timeframes which would allow traders to trade to change position when they receive up to date wind forecasts from their forecast providers. By the time the real time dispatch came around, and with this wind failing to show up, the system was “short” from 12:30 onwards. At 18:30 the system was 1.6 GW short and the system operators dispatched conventional generation, including expensive peakers, to make up the shortfall. This caused imbalance prices to be very high in this period, peaking at 464 €/MWh at 18:00. The impact for a windfarm that traded, say, 80% of its DA forecast in the DA market is significant. It is likely that only 30% of that forecast will have materialised in the afternoon and therefore the windfarm would have had to buy back the forecast error at prices up to €464 per MWh This weekend illustrates the impact extreme weather can have on market prices in the Irish market and demonstrates the importance of having the right partner to manage or to absorb this balancing exposure.

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The First 150 days of I-SEM; Part 1

The Price Spike of January 24th

   

Please contact our Client Services team if you would like to explore the trading, forecasting and balancing services that ElectroRoute can offer to help you minimise the impacts of this volatility on your assets.

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