Overview

On Sunday December 8^th the first named winter storm of the 2019/2020 season tracked from the North West of Ireland. The eye of the depression transitioned from Iceland, across Scotland and then into the North Sea. The strongest winds associated with this system were on the right hand edge of the direction the system was moving in (i.e. to the South West of the centre of depression).

Weather Warnings Issued

On the day before arrival of the storm, Saturday 7th December, Met Eireann published an Orange wind warning for the Western seaboard of the Island and Yellow warning for the rest of the country.

On Sunday 8th at 10am, Met Eireann then upgraded the warning in Kerry to a status Red. This is the most serious warning in the scale.

This Red warning in Kerry was valid from 4pm to 7pm on Sunday evening, with the peak of the storm expected to hit the West coast overall at that time.

The South West, where the winds were forecasted to be strongest, is an area that is one of most densely populated with wind farms on the island. But more of that later.

Impact on the Power System

Day Ahead wind forecasts were high across the whole day (light green line). The out-turn wind generation was much lower throughout the day. The vast majority of this shortfall was due to curtailment of wind farms by the system operators to ensure the security of the power system during periods of high wind penetration.

SNSP Limit:

The Transmission System Operators (TSO) implement a limit on the amount of “non-synchronous” generation on the power system at any one time. This limit is a function of overall consumer demand and is described in the following:

In the early part of this decade, this limit was set at 50%. However, following years of improvements in operations and power system infrastructure by the TSOs, this limit has steadily increased over recent years and is now 70%.

In Ireland, the vast majority of non-synchronous generation is provided by wind farms. Therefore, if interconnector flows were ignored, a simplified version of the SNSP limit could be described as the following:

Adding the out-turn consumer demand and another line which is 70% of demand to the previous chart we can approximately observe which parts of the shortfall in wind generation was due to curtailment and those that are related to forecast error:

It is obvious in the chart above that the wind generation tracks 70% of Demand [red dashed line] for most of the day. In fact, this was a new record for the amount of demand served by wind on the island of Ireland.

Just broke 70% renewables on the power system in the last 2 hours! Well done to all our staff in @EirGrid and @soni_ltd as well as Ireland and Northern Ireland’s world class eco system of developers of renewables projects! @IWEA pic.twitter.com/e3YZhIdEa7

— Mark Foley (@markfoleyce) December 8, 2019

However, there is a clear shortfall in wind generation over the evening peak between 4pm and 8pm. The deviation away from the 70% limit indicates that the shortfall is likely not due to curtailment.

Wind Cut-Out Speeds

During periods of very high winds it can become unsafe for a turbine to continue to generate and the turbine will automatically implement a braking system and reduce power output. The wind speed above which this occurs is known as the “Cut Out Speed”. It can vary by turbine type but is typically 25 m/s.

The shortfall of generation observed in the evening peak can be explained by a number of wind farms in the South West of the country experiencing these cut-out events due to the extraordinarily high wind speeds at the peak of the storm. An example of this can be seen in the plot below based on a number of wind farms.

The reduction in power correlates with the spike in mean wind speed between 17:00 and 19:00, which corresponds to time of the shortfall in wind across the overall power system.

Impact on the Power Market

System Imbalances

The chart below displays the Net Imbalance Volume [NIV] of the balancing market throughout the day.

• Negative NIV values indicate the system is ‘Long’ and there is excess power than needed.
• Positive NIV values indicate the system is ‘Short’ and requires more power to meet the deficit.

In the overnight period, the system was Long, dropping to as low as -831 MW at 04:30.

Throughout the day time the system was relatively Short, with the NIV spiking to 1.3 GW at 18:00 – which is the peak of the storm. A significant portion of this high NIV is related to the shortfall in wind production due to the cut-out wind speeds observed in the South West.

Prices

Overnight

Due to the high wind forecast, Day Ahead prices cleared quite low throughout the overnight period, dipping as low as -11.86 €/MWh at 05:00.

The imbalance price was set throughout most of the night at 0 €/MWh by wind farm dispatch down actions. Notable exceptions were at 00:30 and 09:00 where prices dropped as low as – 130 €/MWh and – 247 €/MWh respectively.

Daytime

Day Ahead prices were relatively low in the daytime period, peaking at 69.72 €/MWh at 17:00 during the evening demand peak.

Imbalance prices were higher than Day Ahead throughout much of the day due to the ‘Short’ NIV seen in the previous chart. Interestingly, the price at 18:00 when the NIV was 1.3 GW short was only 31 €/MWh higher than the Day Ahead price.

In most conditions, a NIV of + 1.3 GW during the evening peak in December should be cause for imbalance prices to outturn far higher. However, given the amount of wind on the system, any dispatchable generators on the system were at relatively low operating levels. At the time of the evening peak, the shortfall was met by these generators increasing their output and Turlough Hill providing the remainder.

Conclusion

For EirGrid and SONI, reaching 70% of non-synchronous penetration on the system is a remarkable achievement.  The Irish system is the first energy system in the world to achieve these levels which are critical to achieving a decarbonised energy system.

The swings in power prices during the day from lows of – €247MWh to highs of €90/MWh demonstrates the importance of having access to a 24/7 trading desk with a deep understanding of weather, forecasts and trading, particularly at times of unusual weather patterns such as storms and extended cold periods.

For more information, please contact clientservices@electroroute.com

The post Storm Atiyah: 8th December 2019 appeared first on ElectroRoute.

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.

On Friday evening there were blackouts across England and Wales causing around one million customers to lose supply. The television news programmes were filled with stories of commuters stuck on immobile, powerless trains, and hospital backup generators failing. National Grid blamed the “unplanned near simultaneous” loss of two generators, and the media has fingered RWE’s Little Barford CCGT and Orsted’s Hornsea offshore wind farm. Ofgem has asked for an “urgent detailed report from National Grid so we can understand what went wrong”.

The last time National Grid was in the dock like this was probably August 2003 when we have dug out the following story from the time:

“A rush-hour power cut has caused major disruption on rail and Tube services in London and the South East. Power returned to the system at about 1900 BST and the rail and tube network took several hours before most services resumed normal operations. Network Rail said about 1,800 trains were affected by the power cut, caused by a fault with the National Grid.
…
Mayor of London Ken Livingstone said at least 250,000 people were affected and said the situation showed the need for a serious look at the National Grid and why power went down for so long.
“We’ve never had this catastrophic failure before and we clearly can’t have it again,” he said. ”

Familiar? But actually in 2019 it really was different. Back in 2003 it was caused by National Grid’s own transmission equipment failing. This time the problem was simply the very unfortunate disappearance from the grid of power stations at a time when (we speculate) that the system was seemingly very light on inertia. Disconnections followed.

Earlier on Friday National Grid ESO tweeted a message that:

“this morning approx 50% of GB’s electricity was generated by wind! It’s not the highest total amount of wind ever generated – that was 12456MW on 7th Jan 2019 – but it’s wind power’s biggest ever proportion of GB electricity”.

The actual figure revealed in the small print was 47.6%, which is still about 45% higher than it ever got to in 2003. National Grid later in the day published figures showing that 67% of generation was in their “zero carbon” category, including 8% solar and 17% nuclear. It is something of a shame that this good news will be overshadowed by what happened later.

National Grid routinely prepares for the loss of the largest plant on the system, traditionally Sizewell B, and equivalent network infrastructure losses, but nowadays this limit has been upped a little in anticipation of the new generation of nuclear units that will come in at around 1630MW each. A loss of more than 1320MW and less than 1800MW would be considered by National Grid an abnormal change to operating conditions, but it aims to cope under its security standards.

Little Barford (roughly 650MW at the time) and Hornsea (eventually 1217MW, but still being commissioned so roughly 750MW) added together equate to something in this region. Accordingly it would be expected that the system might have managed to ride through what is a perfect storm, but the other factor of lots of non-synchronous infeed at the same time probably made things very difficult. Around the nadir of system frequency (see this recent blog for an explanation of frequency) things stood at roughly 48.889Hz.

Under the Electricity Safety, Quality and Continuity Regulations 2002, National Grid has a legal duty to keep system frequency to within 1% of a 50Hz target, in other words between 49.5Hz and 50.5Hz. For the vast vast majority of the time it is kept within its own operational limits of 49.8Hz and 50.2Hz. Occasionally it fails, perhaps for a few seconds every day, and very occasionally frequency can deviate from the envelope and go on what is called an “excursion” (in the parlance) outside 49.5/50.5Hz.

A “reportable excursion” is one outside that 1% limit which lasts for more than 60 seconds. These are actually very infrequent in the modern system, and we believe that the previous event was back in May 2008 (48.792Hz). And before that only 40 or so events of that sort have occurred in Great Britain since the mid-1970s. So last Friday was definitely something that will be the subject of many industry post-mortems, and the more so because significant load was shed this time. Were all of the relays correctly configured? Was there sympathetic tripping?

National Grid has already stated that there are lessons to be learned, and it will be intriguing to disentangle this tale once more information is in.

The post Blackouts in Britain appeared first on ElectroRoute.

July 14^th, 2019 saw the final of the Men’s Wimbledon Singles as well as the Cricket World Cup Final. As the clock reached four hours fifty-seven minutes, in what became Wimbledon’s longest singles final, Djokovic beat Federer 7-6 (7-5) 1-6 7-6 (7-4) 4-6 13-12 (7-3). While this was happening, another major sporting event was also underway as England faced New Zealand in the Cricket World Cup Final. Both sides scored 241 in their 50 overs and were level on 15 when they battled for an extra “super over” apiece. England eventually were declared winners because of having scored more boundary fours and sixes. Yet another record was achieved: the first tie in a Cricket World Cup Final.

The low probability of record ties occurring in both events, extending the overall length of each match, could be considered practically impossible for electricity system operators to predict and forecast for.

‘TV Pickup’ is known as a period in which there is a sudden, synchronised surge in national electricity demand on the grid due to certain TV broadcasts attracting many viewers. Ad breaks also play an important role in this phenomenon as viewers take this time to switch on electrical appliances, such as kettles and toasters at the same time.

In Ireland, the system operator aims to achieve a nominal frequency on the island of Ireland of 50 Hz, this occurs when demand and generation are balanced. The normal operating frequency range is between 49.8 Hz and 50.2 Hz. An excess of generation leads to an increase in frequency and conversely, an insufficient amount of generation leads to a decrease in system frequency. A sudden change in demand, generation or interconnector flow leads to a sudden fluctuation in system frequency.

The TV pickup that occurred on July 14^th, 2019 can be detected by analysing system frequency data, published at five second resolution by Eirgrid.

The Wimbledon Men’s Singles Final began at 2 p.m. Between 13:50:00 and 13:59:00 the system frequency was kept mainly in the 50.04 Hz – 50.06 Hz range, perhaps preparing the system for the expected surge in demand for the 2 o’clock match. At 13:59:15 system frequency was 50.06 Hz, just ten seconds later at 13:59:25 system frequency had dropped to 49.99 Hz.

Arguably more difficult to predict was when audiences would turn off their T.V. following the end of both matches – when would both matches finish? And how long after the end of each match would audiences switch off?

The Wimbledon Men’s Singles Final lasted an incredible four hours and fifty-seven minutes, finishing in the evening at 18.57, whilst England were declared the Cricket World Cup champions at 19.33. Looking at system frequency, we can again see the effect on the grid.

One minute after the end of the Wimbledon Final, at 18:58:00, system frequency was 49.96 Hz, 6 minutes and 40 seconds later it had climbed back up to 50.02 Hz as demand began dropping from the grid. Ten minutes after the winners of the Cricket World Cup were declared, system frequency saw a dramatic climb. At 19:42:25 system frequency was 49.96 Hz, by 19:44:15 it had jumped back up to 50.03 Hz.

Reacting to a sudden change in system frequency, inertial response can be viewed as the first responder. Inertial response is a capability of large synchronous generators. The rotating masses of these generators can speed up or slow down and change system frequency, responding in 0-5 seconds. The system operator may then employ slower reacting reserve systems.

Planning for and predicting the behaviour of electricity consumers during large sporting events is evidently a high priority for system operators, with high levels of uncertainty. How many people are expected to view the game live? What affect on electricity consumption will ad breaks have? It is therefore of high importance for the system operator to understand, predict and be prepared for the behaviour of individuals residing in Ireland.

There is clearly a group of ardent cricket followers on the island, but obviously not as many as there are in Great Britain, home of the English tournament hosts, judging by the below screenshot shared by National Grid ESO:

The TV pickup on the Great Britain system was 700MW+.

The post The Effect of Large Sporting Events on the Grid appeared first on ElectroRoute.