Extending temporary emergency generation (TEG) will cost Irish electricity consumers an estimated additional €229 million. The extension is needed because the capacity auctions are still not delivering enough capacity.
A return to market-based procurement is needed to minimise long-term costs to consumers, and to ensure that these temporary measures stay temporary. This can be achieved through an appropriately calibrated capacity auction.
The cost of extending TEG
On 18 September 2026, the Commission for Regulation of Utilities (CRU) directed EirGrid to exercise options in its existing TEG contracts, retaining the units for the winters of 2027/28 and 2028/29.1 These arrangements were put in place to address forecast electricity capacity shortfalls, as Ireland’s capacity market had failed to deliver sufficient capacity.
The CRU estimates the impact on residential bills at between €0.79 and €14.96 a year from 2026/27 to 2029/30.
This brings the total cost of TEG to Irish consumers to €1.4 billion. Given this, it is worth asking why these arrangements are still needed and how to return to market-based procurement.
Ireland buys electricity capacity centrally to guard against shortfalls
Ireland procures electricity capacity centrally because the energy market alone is unlikely to deliver sufficient capacity at times of system stress, such as winter peaks. The reason is the “missing money” problem: peaking plant runs too rarely, and the prices it can charge are too low, to recover its full costs.
A capacity market is a common remedy for this issue in electricity markets: generators are paid an annual fee to be available when called upon. That fee is typically set through an auction, into which generators bid based on the payment they need to stay available (or, for new plant, to be built), net of expected energy and system services revenues.
Ireland and Northern Ireland buy this capacity together, through the Capacity Remuneration Mechanism (CRM) in the Single Electricity Market (SEM). A T-4 auction is held roughly four years ahead of the year it covers.2
The auctions include two administrative caps that limit what generators may bid.3
- An Auction Price Cap of €230,000 per de-rated MW-year for the forthcoming T-4,4 which applies to all capacity.5
- An Existing Capacity Price Cap of €57,928 per de-rated MW-year, which limits what existing plant may offer on the basis that it needs to recover only its going-forward costs.
The capacity market has not delivered sufficient capacity
In the first part of this decade, demand grew faster than forecast, old and inefficient plants were retired and a material volume of T-4 capacity contracts were delayed or never built. As a result, the electricity adequacy gap widened.
The failure of T-4 contracts to deliver points to a flaw in the capacity market’s design. A developer that wins a capacity contract posts security and faces termination charges if it does not deliver. As construction costs rose and new gas plants became harder to finance, forfeiting the security was sometimes cheaper than building the plant and incurring losses.
The CRU addressed this shortfall by directing EirGrid to procure TEG, which was contracted outside the capacity auctions.
The CRU decision extends TEG by up to two years. TEG 1 (241 MW) is extended for two years at €177 million and TEG 2 (412 MW) for one year at €52 million. The CRU’s reasons for the extension are:
- delays and cancellations affecting capacity contracted through the capacity auctions;
- the delay to the Celtic Interconnector;
- reduced performance from existing units; and
- planned outages for refurbishment and upgrades.
The first of these shows that the capacity market is still not delivering sufficient capacity.
Market-based procurement is preferred to out-of-market contracts
The extension means TEG 1 will now be in place for five years rather than three. Over time, capacity procurement should transition back to a properly parameterised market mechanism because an auction has clear advantages over out-of-market contracting. Figure 1 below summarises these advantages.
Figure 1: The advantages of a market-based mechanism
Table 1 below compares the estimated cost of the TEG extension per de-rated MW-year, based on assumed de-rating factors, with the Auction Price Cap, the Existing Capacity Price Cap and the clearing prices in the two most recent auctions. These values may not be directly comparable, as:
- the original TEG contracts needed to recover their costs over a shorter period than units successful in the capacity auctions; and
- CRM units also earn energy and system services revenues and pay reliability option difference charges, whereas TEG sits outside the market.
Even so, the comparison suggests that such arrangements may come at a premium.
Table 1: The cost of the TEG extension
| Basis | Euro per de-rated MW-year |
|---|---|
| TEG extension, weighted average, de-rating 80% | 320,200 |
| TEG extension, weighted average, de-rating 90% | 284,600 |
| Auction Price Cap, T-4 CY2030/31 | 230,000 |
| Existing Capacity Price Cap, T-4 CY2030/31 | 57,928 |
| Clearing price, T-4 CY2029/30 (March 2026) | 135,500 |
| Clearing price, T-1 CY2026/27 (July 2026) | 53,979 |
Note: Weighted average across both tranches, TEG 1 retained for two capacity years and TEG 2 for one: total cost (€229 million) divided by 894 nameplate MW-years (241 MW × 2 + 412 MW × 1), then by the de-rating factor. De-rating factors are assumed.
Auction parameters need review to enable a return to market-based procurement
TEG is a non-market backstop procured outside the auctions. Over the long term, consumers are better served by the disciplining pressure of a competitive auction. However, to make that move, the auction parameters need to be revisited. We propose three changes.
1. Build in headroom for delay
Construction delay is normal. Capacity requirements that are calibrated to on-time delivery will be short whenever a project slips. EirGrid already factors in such uncertainty on the demand side, through its Least Worst Regrets scenario approach. A similar approach could be considered on the supply side.
2. Test both caps against what consumers actually pay
An Auction Price Cap below the cost of new entry excludes projects rather than disciplining them, and can push procurement towards dearer out-of-market deals. Equally, an Existing Capacity Price Cap set too low can force existing units out of the market, even where a unit-specific price cap is available. While recent auctions have cleared below the caps, the SEM Committee has said it will review the Best New Entrant value and keep the Existing Capacity Price Cap under review. Each cap should be assessed against the total cost to consumers, including the cost of a potential backstop.
3. Make delivery assurance proportionate to the cost of failure
The SEM Committee has performance security and termination charges in place, ranging from €20,000/MW to €60,000/MW for the T-4 CY2030/31 auction. The test is whether they reflect the cost of the backstop that non-delivery obliges consumers to buy.
Market-based procurement benefits consumers
This does not argue against holding a backstop such as TEG. A system operator should be able to keep the lights on, and a regulator should allow its cost to be recovered. But a framework that keeps having to buy outside the auction what the auction failed to deliver is not working in consumers’ interests.
Endnotes
1. CRU (2026) “Temporary Emergency Generation arrangements retained to support electricity security of supply”, 18 September 2026.
2. A smaller T-1 auction is held shortly before the capacity year starts to top up whatever is still missing.
3. SEM Committee (2026) “CRM T-4 CY2030/31 Capacity Auction Parameters Decision Paper”, SEM-26-38, 31 July 2026.
4. The forthcoming T-4 is for CY2030/31, to be held on 25 March 2027)
5. Capacity is bought in de-rated megawatts: nameplate capacity adjusted for the probability that a unit is available when the system is tight.