We answer the key questions on energy cost, supply and infrastructure in Ireland today.
We answer the key questions on energy cost, supply and infrastructure in Ireland today.
In 2015, almost half (43%) of the electricity we used was generated from natural-gas fuelled power stations and about one sixth came from coal (16.9%). About a third of the power we consumed was generated from indigenous sources like wind (22.8%), peat (8.8%) and hydro-electricity (2.8%).
The figure below shows the relative proportion of primary energy input into electricity generation in Ireland whereby including the energy lost in transformation (45% of the input) increases the relative weight of coal and peat in the generation mix.
Having a diversity of energy sources for electricity generation reduces our dependence on any one source and insulates us from the worst impacts of a disruption to that supply. In relation to gas, which makes up the largest part of our generating capacity, we are dependent on a gas network that routes through a single pipeline in Scotland. A project to reduce that single pipeline dependency has been approved by the CER. Having other sources, like wind, and for the time being coal, means that we can increase power generation in the event of the disruption of one source and ensure that we are able to generate enough electricity for everyday life.
|Electricity Generation Fuel Mix||1990||2014||2015||2015 % Share||Price Volatility*|
|* Ranking of 1-3 based on standard deviation of Irish fuel prices, ESRI 2015; 4 based on fixed REFIT price.|
The schedule of plants chosen to satisfy the forecast electricity demand is determined every day and 24 hours in advance. It is adjusted in real time in response to unforeseen events. The price of a plant’s power is a crucial determinant of whether it will run, but its location is also critical because congestion on the grid is a serious concern. Low-carbon renewable energy generators, such as wind and biomass, are given priority access to the grid. If they are available to run and are generating power, the System Operator must accept it. For every half-hour of the day, the Market Operator estimates the likely demand and, after taking account of any wind power that will be produced, schedules sufficient generation to meet it. Some types of plant such as the coal-fired station at Moneypoint are expensive to build but cheap to run, so their bids are competitive and these base-load plants run most of the day producing electricity. Combined heat and power plants are highly efficient in their fuel use (defined as over 80%) and so have priority access to the grid. Although most fossil-fuel generators compete on price, some have valuable technical characteristics that make them competitive in situations where, for example, the power demand is changing fast.
There are three types of power plant operating in Ireland – base-load, mid-merit and peak generators. Base-load plants, such as the one at Moneypoint, provide the bulk of the country’s electricity needs. They are the lowest-cost plants and are most economically used at maximum capacity. Mid-merit generators supply power when the daily electricity demand picks up in the morning and they shut down when the demand drops off in the evening. Mid-merit, or load-following, plants adjust their output as demand fluctuates during the day. As more wind is connected to our electricity system, the requirements for and the demand on load-following plants will grow because of the natural variability of this type of power. Peaking power plants operate only during times of highest demand, which are around the start and end of the working day. However, the duration of operation for peaking plants may vary from hours per day to less than a couple dozen hours per year. Peaking power plants include pumped storage hydro-electricity and open cycle gas turbine power plants.
Power plants operate in response to demand, but electricity must be produced all the time to maintain the quality of supply and to achieve the lowest wholesale price for the commodity. Our needs change seasonally and daily, and a surge in demand must be met by an increase in supply in real time, so some fast-acting generators are essential. These ‘peaking plants’ are expensive to operate, but they do provide a reliable supply at an acceptable cost. The System Operator (SO) prepares for surges in demand by having some plants in a state of readiness. The choice of which plant is “dispatched” to meet the additional demand depends on where it is located and the price of its electricity. Generators that are located at some distance from the centre of demand can only be dispatched if the grid has sufficient capacity. In general, the stronger the grid, the greater the freedom is for the SO to dispatch the lowest cost plant as determined by the Market Operator and by doing so achieve the lowest wholesale price.
There are a number of factors that influence the choices we make in how we generate our electricity. At EU level, a big driver is the need to meet our renewable energy target and to reduce greenhouse gases by 20% by 2020 (compared to 2005). In order to meet this target, the Irish government decided that 40% of our electricity consumption should come from renewable sources, such as wind. Government policy strikes a balance to ensure that sources of energy and power generation are cost-effective, reliable and have minimal environmental impact. There are also a number of system requirements as well as market and regulatory mechanisms that influence the make-up of our electricity generating sources.
We need new power lines to meet the rise in electricity demand as our population increases and as we prepare for and experience economic growth. It may appear that we have a sufficient number of power lines to meet current and projected demand until 2020, but forward planning is essential. The need for new power lines is based on expectations of what will happen, and their construction requires a long lead-in time.
There are four reasons to build new power lines and expand the electricity network, and the recovering demand for electricity means that all four currently apply to Ireland. These reasons include:
Interconnection of electricity transmission systems between the Republic and Northern Ireland enables the creation of an efficient single all-island electricity market. This means that consumers North and South benefit from increased competition between power generators and from the reduced need to maintain spare capacity. Eirgid estimates that the north-south interconnector will save consumers up to €40 million per year.
No, we could not. Transmission lines and a national transmission system are essential to a functioning electricity system. In the absence of a transmission system, power would need to be generated and distributed locally, which is not economically viable outside of the large population centres. Underground cabling is possible but at greater cost and it is currently being considered as part of an option for the Gridwest project. Ireland’s commitment to a mix of renewable and non-renewable fuel sources in electricity generation will require a reliable national transmission infrastructure in the future.
Connecting our power system to Britain reduces the need to duplicate services and provides more competition in the electricity market. It allows us to import electricity when it is cheaper there and to export electricity to Britain on days when we generate more than we need, as we do from wind on windy days. The interconnector to Britain also helps to secure our electricity supply by providing back-up sources of power. At present we import between 8-10% of our electricity needs from Britain and our electricity prices are estimated to be approximately 9% lower as a result.
In principle, the country that benefits most from an interconnector should meet the cost of that infrastructure. In the case of the East-West interconnector between Britain and Ireland, the Irish consumer has benefitted most because we have access to a much larger market with the effect of reducing prices here by 8-10%. It was therefore publically funded by Ireland and is owned by EirGrid.
At the time it seemed that for the British consumer, access to electricity from the much smaller Irish market would not significantly reduce prices in England. However, the regulator in Britain has recently flagged an interest in a proposal for further interconnection where renewable energy trading was a consideration. Considerable financial support is also provided for these projects from the European Union, because they contribute to the EU’s aim to create a single electricity market across Europe.
While our electricity system could function without interconnectors, they play an important role in keeping prices down and providing a more efficient power system. Since the East-West interconnector was built, the amount of electricity traded over the interconnector between Ireland and Britain has steadily increased and allowed us to export surplus wind power and buy in cheaper electricity from Britain.
Further interconnection will need to be assessed on a case-by-case basis, but the increased use of renewables such as wind and solar may justify the building of more interconnectors with other countries. If national electricity systems across Europe are well connected, the resulting increased competition is likely to reduce prices.
At present, between 7-8% of electricity generated is lost in transmission and distribution. By investing in new technology, we will see the development of a “smart grid” that can better control supply and demand and incorporate intermittent sources of power such as solar and wind. A smart grid will also allow us to switch to a “multidirectional” flow of electricity where power flow can alternate between local sources (e.g. wind power) and central sources depending on usage and weather conditions. The smart grid could make a meaningful contribution to achieving Ireland’s energy efficiency target of 20% by 2020, saving €2.25 billion in energy costs in the process.
Since 2007, the electricity markets in Northern Ireland and the Republic of Ireland have been part of a Single Electricity Market (SEM). In market terms this is a mandatory wholesale pool where electricity generated on the island is traded. The Irish SEM was the first pool market across multiple jurisdictions and dual currencies in the world.
A key long-term energy policy of the European Union is to implement a more open and competitive single European electricity market. To meet the EU’s ‘Target Model’, the regulations governing the SEM on the island of Ireland are being adapted into the Integrated Single Electricity Market (I-SEM), due to come into operation in 2018.
The I-SEM aims to provide higher levels of competition, increase transparency, and reduce the price of electricity for consumers. Instead of a market where generators sell their electricity to the SEM and the spot price is decided on after, new rules will require competitive purchasing of electricity in advance based on supplier generation and consumption forecasts. In addition, capacity payments to ensure generation capacity will no longer automatically be allocated by the regulator but rather will be competed for in an auction.
Capacity payments are those made to electricity providers for their available generating capacity, irrespective of whether they supply any electricity to the grid. The capacity payment scheme was established as part of the single electricity market (SEM) to ensure that there would always be sufficient spare capacity to supply electricity to meet peak demand. Capacity payments are our insurance policy to prevent electricity shortages. The payment provides a guaranteed, but limited, return to electricity suppliers and so provides an incentive to invest in new power plants. In 2015, the total revenue for electricity generators from capacity payments was €478 million (on average 18% of total revenue). Plants that are needed to operate only in rare circumstances receive the highest proportion of their revenue via capacity payments. In 2015, peaking plants received on capacity payments for 54% of their revenue.
During the economic boom of the early 2000s, there were concerns that energy demand would increase to the point where it would outstrip capacity. At the same time, investors were unwilling to build new power stations without a guaranteed return. In response, the Commission for Energy Regulation (CER) ran a competition for the construction of new power plants, which included a minimum price guarantee and a condition that the supplier would still receive payments even if the generating capacity was not needed. During the economic recession, the expected increase in demand for electricity did not materialise. As a result, one of the facilities constructed under the CER competition, Tynagh Energy continued to receive payments while not actually operating and supplying electricity. Approximately €66 million was paid to Tynagh Energy in 2015 but this agreement expiered in March 2016.
Wind-generated electricity has priority access to the national grid over non-renewable sources, so wind energy is generally accepted and distributed within the system. However on very windy days, the electricity generated can exceed the capacity of the system to accept it. In those situations, some of the wind energy providers may be blocked (“curtailed”) from the grid. The proportion of electricity blocked in the past few years has amounted to 3-4% of the wind electricity generated. A constraint payment, funded by the Public Service Obligation (PSO) levy, is provided to wind electricity operators when they are blocked from the grid. This amounted to €123 million in 2013, but the payment is planned to cease in 2017. In recent years, the East-west interconnector has allowed excess wind energy to be exported to Britain, reducing the amount that needs to be paid for curtailment.
Public Services Obligation (PSO) subsidies are paid to achieve certain policy aims around sustainability and security of supply that would not otherwise be met by the market. In Ireland, the government policy is to encourage renewable sources of electricity, provide for sufficient generating capacity and support indigenous sources of electricity generation. Providers of renewable electricity are granted a minimum price for the power they sell to the national grid. If the wholesale price of electricity falls to less than this minimum, the balance is paid from the PSO levy. It is estimated that this payment will double in the future as more renewables enter the system and we move to achieve the target of 40% electricity supply from renewable sources by 2020.
The Public Service Obligation (PSO) levy cost each electricity customer €5.01 per month in 2015/16, or €60.09 per annum. For the period 2015/2016, €325 million was paid annually from the PSO to electricity suppliers. Of that total, €181 million was paid for renewables, €122 million was paid to peat generators and €47.5 million went to operators that were critical to security of supply. PSO payments for 2016/17 increased to €392.4 million, driven by lower wholesale electricity costs and greater amounts of renewables on the system.
Price guarantees have been granted to some electricity generators to achieve certain strategic objectives for our electricity system. Minimum guaranteed pricing helps to support the development of renewable electricity by reducing the uncertainty for investors and lowering the cost of capital to develop renewable projects. Similarly, minimum pricing supports the development of spare capacity in the system to allow for future growth. As that capacity may not be fully utilised, investors need some guarantees to develop these projects and minimum pricing provides this. The other price-guaranteed energy source is peat. As we are an island nation that imports virtually all our fossil fuel, it was deemed strategically important to have electricity generating capacity from locally sourced fuel.
When gas prices are high, the wholesale price of electricity exceeds the minimum price guaranteed to preferential suppliers (wind, capacity, security), and payments from the PSO are reduced. When gas prices are low, such that the wholesale electricity price is below the minimum price guarantee, payments from the PSO increase to compensate preferential suppliers for the price difference, or to cover their costs when not running their plants. When wind generation is high, payments from the PSO are increased to support the increased amount of wind energy coming into the grid. More wind energy also pushes down the wholesale price, so increasing the PSO further to compensate other non-wind, preferential generators. When wind generation is low, the PSO contribution is reduced, because the guaranteed price paid to wind energy is reduced. In addition, less wind energy means that the overall wholesale price of electricity may increase, which can further reduce the PSO paid to other, non-wind preferential generators.