D-1 versus D+4

Currently ‘Synergy Service’ publishes the planned electricity price for the following day. This is called the D-1 price. Four days after the trading day, the final market price is settled. This price is called the D+4 price and it is the price used to settle trades among the players in the electricity pool. It is interesting to see how close plan and actual turn out to be. If the D+4 (actual) turns out to be significantly different from the D-1 (plan) then the wrong price signals are being sent by Synergy Service and the optimal demand response (DR) will not be achieved by the Synergy Modules using Synergy Service.

The following chart from Synergy Data shows two days from last week. D-1 (plan) is shown as a solid bar chart and the settled D+4 (actual) price is drawn as a line graph. It is clear that for most of the time D+4 and D-1 are very close. An electricity cost reduction algorithm based on D-1 would yield good cost optimisation. However at around 9:00pm, for about 1 hour, the cost of electricity deviated significantly from D-1.


What we are now focussed on, at Synergy Module, is trying to find some way to improve our Synergy Service signals to bring them closer to the eventual D+4. Obviously, this will reduce the cost of electricity for our customers by enabling them avoid usage during such a peak. Reducing usage at that time will lower the peak and bring down the cost of electricity for all users.

Synergy Data Released

This week, a number of very large companies have started to use Synergy Data to analyse and manage their consumption of electricity. The software enables them negotiate more effectively with suppliers to secure better pricing. Users can form an opinion as to how their usage pattern affects their pricing and can establish how much ‘profit’ their suppliers make versus the SMP tariff.

If your company could benefit from the use of energy management software, send me an email requesting a free online account.

Putting the money in DR

The key challenge facing the development of a commercial DR project in Ireland is to create a market reward for consumers who modify their electricity consumption to match available supply. There is an active wholesale, but not retail, market for electricity in Ireland. This market is bid in by the Generator Units (market name for companies that operate generation plant) on the day prior to production based on expected demand. Computer software optimises for lowest cost the various bids and publishes the run schedule.

A projected system marginal price for one day during the past week is shown above. On that day the highest price was three times the lowest price. The X axis is one day divided into 48 hour segments and the Y axis is Euros per MWh.

If retail electricity prices varied by the same amount as wholesale prices then demand would start to match supply as users availed of cheaper electricity.

The objective of DR is to get retail electricity prices to vary in real time (Smart Meters) and to give consumers the tools (Synergy Module and Synergy Service) to manage their demand to minimise price.

This week I had my first face to face meeting with the Commission for Energy Regulation (CER) and although the challenges were obvious the people I met could clearly see the benefits of implementing DR. I remain hopeful that we can find a mechanism to monetise DR on the Ireland of Ireland to make it attractive for consumers to sign up.

If real time DR is not developed in Ireland then we have no hope of achieving the targetted 30% renewables that our government is aiming for.

Podcast on EDM

I really like this podcast, from IBM, on EDM.


Please take seven minutes to listen to it….

This article relates to the same project if you prefer to read.


In the 1970s, IBM’s position in the computer industry was akin to Microsoft’s position today. Over the last week I heard a news bullitin that IBM are now larger the the combined capitalisation of the Irish stock Exchange. Its interesting that such a large company are in the EDM space. This is an IT vertical market that could be very large. The effect will be to create a supergrid of smart electrical devices and smart electricity meters that offer consumers enhanced functionality while delivering energy savings, lower cost and enhanced renewables penetration.

Generation Adequacy Report 2008 to 2014

The Eirgrid Generation Adequacy Report 2008 to 2014 was published recently.


The report states that Ireland is facing a tight electricity supply situation:

“The most significant factor influencing this is the poor availability of the generation portfolio. Improved availability performance would greatly reduce the risk to security of supply. However if availability continues at the current low levels, then the system is facing immediate deficits.”

We are moving to less diversity of supply as all new generation capacity planned in the near future is either (Russian) gas or wind generated power.

The report recognises the benefits of moving demand to off-peak hours. “Shifting 1% of annual consumption from peak to off-peak hours would remove the requirement for approximately 135 MW.”

With regard to wind power generation (WPG) the report states. “There is also considerable investor interest in wind powered generation, however, due to its inherent characteristics, it offers limited generation adequacy benefits. Furthermore if WPG is installed at a linear rate of 270 MW per annum there would be just over 1,700 MW installed by the end of 2010. This should be sufficient to enable 18.0% of the electricity requirement to be provided from renewable sources and would mean that the Government’s target of 15% by 2010 is exceeded.”

The problem with wind energy is, of course, that it’s only available when the wind blows. That means that it has very little effect on supply adequacy.

Furthermore the contribution of WPG towards generation adequacy (i.e. Capacity Credit of WPG) has not keep pace with the growth in installed capacity or energy supplied. In fact, while installed WPG capacity has increased by 40% per annum over the last 5 years, in the same period the capacity credit (as a percentage of installed WPG capacity) has fallen from 35 to 24 %, see Figure 4-7. As outlined in Section 2.3(b), this is due to the inherent inability of WPG to behave as a number of fully independent power plants. All WPG in Ireland tends to act more or less in unison as wind speeds rise and fall across the country. The probability that all WPG will cease generation for a period of time (as a result of wind conditions) limits its ability to ensure continuity of supply and thus its benefit from a generation adequacy perspective.

EirGrid recognise the benefits of moving demand to off peak times. They do not acknowledge in the report that energy demand management (EDM) can improve WPG adequacy if the EDM is operated based on actual current wind energy production rather than on tine based tariffs. In particular the possibility of stimulating demand at times of excess wind energy could reduce or eliminate the need for wind farm curtailment.

Pumped Hydro Storage versus EDM

I wanted to compare the cost effectiveness and carbon efficiency of EDM to energy storage using pumped hydro, so I did the following analysis. Pumped hydro storage is about 80% efficient per cycle. First, I was interested to know how big a reservoir do you need for a viable pumped hydro storage facility so I did the following calculation. Then I did some analysis to see what the payback for the investment would need to be.

U = mgh      where

  • U is energy measured in Joules
  • m is the mass of water in kgs 1m cubed = 1,000 kg
  • g is the earths gravitational constant of approximately 10 m/s/s
  • h is the height in meters through which the water is cycled

So if we want, say, a 20MW capacity for 10 hours = 200MWh

1 Joule = 1 Watt for one second

therefore 200MWh = 200,000,000 x 3,600 Joules = 720,000,000,000 Joules

therefore 720,000,000,000 = 10 x h x m   or   72,000,000,000 = h x m

So if we had a reservoir at a height of 100m

m = 720,000,000 kg of a water reservoir

1 cubic meter of water is 1000kg so we need 720,000 cubic meters of a reservoir. Incidentally we would need a water source that could supply or sink 20 cubic meters of water per second depending on whether we were pumping or generating.

This would be a reservoir 300m x 300m x 8 m deep. And for those of us familiar with acres as a unit of area this would be just over 20 acres. I estimate that to build such a reservoir from concrete would take about 50,000 cubic meters or 100,000 tons of concrete and would cost about €15,000,000 to build. Adding another €5,000,000 for pipeline, plant and switchgear would bring the project to a total of €20,000,000.

So given annual maintenance and running costs of €300,000, an annual landowner payment of €200,000, and a required ROI of say 10% to bring investors on board, the annual income required for break-even for the facility would be €2,500,000 per annum or €8,500 per day allowing for some downtime.

Assuming 50% utilisation (i.e. 100MWh generated per day) this equates to €0.085 per kWh. Also a cost allowance for the 20% cycle losses needs to be factored into the cost justification so a cost of €0.105 would be required. So in order for pumped hydro storage to be financially effective a mean daily delta of €0.105 per kWh would need to exist between peak demand and peak generation times. To achieve this cost per unit stored we have factored in very high utilisation figures. These might not be justified. In terms of carbon neutrality, pumped hydro storage is very poor because it uses large amounts of concrete and iron in its construction and it loses 20% of its energy in every cycle.

How does EDM costs stack up by comparison:

If we assume that a capital budget of €10,000 to meter and control 100kW of load. This works out at €100 per kW. Let us assume that each kW of controlled load is used for 1kWh of EDM per day. If we assume a payback period of 5 years, the capital cost is €20 per kW per annum. We therefore have 350kWh of storage for a capital cost of €20 or €0.057 per unit. The consumer (and aggregator) will also require a financial incentive to participate of say €0.05 per unit. This produces a cost of €0.107 per kWh controlled.

On initial costings pumped hydro and EDM seem similar. However EDM has three significant advantages.

  1. EDM produces less carbon than pumped hydro storage.
  2. EDM requires lower duty cycle factors to be cost effective.
  3. EDM reduces the cost of energy to participating consumers.

All in all, I think the case for EDM versus pumped hydro storage is very strong.

Demand-Side Bidding and the IEA

The International Energy Association (IEA) uses two acronyms DSM and DSB which can be defined as follows:

  • Demand-side management (DSM) is the control of electrical consumption for cost and ecological reasons.
  • Demand-side bidding (DSB) is a market place that creates a financial incentive for EDM.

This web site uses the phrase energy demand management (EDM) to mean the real time control of electrical load and generation plant to stabilise an electrical grid. EDM is therefor a subset of DSM. DSB is a necessary prerequisite for the implementation of EDM.

The International Energy Association (IEA) has a web site specifically devoted to DSM (http://dsm.iea.org). This site has a ‘key publications’ section from which you can download a number of interesting documents. The one I found most interesting is ‘A Practical Guide to Demand-Side Bidding’. You must register to download this document so I cannot publish a URL. This document is explosive in its content and its impact for Ireland because it states that demand side bidding is important on any grid but its importance is amplified in the context of a small network with high renewable energy availability.

The document gives a seven step implementation plan to establish a demand-side bidding (DSB) programme within a country. These seven steps will drive my business model development over the next year.

  1. Identify the needs of the buyer (i.e.TSO/EirGrid)
  2. Target providers (understand electricity consumer processes)
  3. Adapt Product (match ‘needs’ ofbuyer to ‘process’ of provider)
  4. Define technologies (technical solution to control monitoring and communications)
  5. Make Business Case (Define costs and benefits)
  6. Refine selection of product (Adjust business case to find best match)
  7. Implement (Establish bid mechanism and negotiate contracts)

The Irish Electricity Market

The Electricity Supply Board (ESB) is eighty years old this year. It was founded in 1927, the same year my father was born. It is hard for me to imagine that as a young child he did not have electricity at home. Up to that point electricity was generated by city corporations for local distribution. The development of the Shannon hydroelectric scheme and the creation of the national transmission grid that resulted triggered the Irish government into forming a single state owned monopoly for electrical generation and transmission. In Ireland, electricity and the ESB became synonymous. Most people in Ireland still view this as the market situation but times have changed considerably.

The European Union (EU) directive 96/92/EC, published in 1996, required member states to open their electricity markets. From the year 2000 this directive is being gradually implemented in Ireland. The ESB lost its monopoly on electricity production and distribution in Ireland. The ESB was divided into two separate business units, ESB Generation and ESB Networks. ESB Generation now competes as any other wholesale elctricity generation company in the state. ESB Networks maintains the distribution network.

Once the ESB monopoly was broken, the Commission for Energy Regulation (CER) www.cer.ie became the overall regulator of the Irish energy market including electricity. A new organisation EirGrid www.eirgrid.com was founded to act as the  System Operator and the wholesale market operator for electricity in Ireland.

How does this new structure affect the regulation and administration of EDM projects, existing or proposed, in Ireland? Any EDM projects must be initiated and licensed by the CER and must be operated by EirGrid.

In order to facilitate wind energy penetration, EDM must be real time. The only real time EDM in Ireland is STAR and that is limited in size, is currently closed to new entrants, and is designed to assist in rare cases of generation plant failure. Obviously if I am to implement an EDM business in Ireland I will need the necessary regulatory and administrative procedures to be implemented bt CER and EirGrid. The question is therefore, how disposed to EDM are CER and EirGrid.  The following link answers that question:-


CER are planning to implement a pilot Demand Side Management (DSM) project involving smart metering and time of day tariffs. Surprisingly the discussion document in the above link does not mention wind energy at all. I think that this is because the project is in response to initiatives at a European level and it is only in the Irish context that EDM takes on a specific signifiacance in relationship to wind energy.

Also you will notice that CER use the acronym DSM while I use the acronym EDM. Do these mean the same thing? From the published literature, demand side management appears to be a very broad term that includes all kinds of energy efficiency projects at the consumer. DSM includes EDM as a subset. Energy demand mangement is specifically about the real time generation, curtailment and consumption of electricity to achieve grid stability.