The UK energy transition is often viewed through the lens of the British energy system, to the exclusion of Northern Ireland – a region that is undergoing its own energy system transformation.

When the last coal UK power plant closed at Ratcliffe-on-Soar in early October, the widespread global coverage of the milestone made no mention of Northern Ireland’s successful coal exit in 2023.

The Kilroot power station in County Antrim started running on gas in April, several months after it stopped burning coal. The fuel switch allowed Kilroot to keep generating, allaying fears in some quarters of blackouts in the coming years.

Those fears appear misplaced. But there are concerns around the pace and trajectory of Northern Ireland’s switch to cleaner power sources.

Northern Ireland’s energy transition faces a unique set of challenges thrown up by its position within post-Brexit UK and the all-Ireland Single Electricity Market
Expanding interconnection capacity and developing a new renewable energy support scheme are crucial to ending Northern Ireland’s renewables investment hiatus
Regulatory barriers are hindering the deployment of energy storage. This will be essential for integrating high levels of wind generation into Northern Ireland’s small grid
Brexit created additional complications around Guarantees of Origin certificates. This made wind and solar projects there less attractive than in the Republic of Ireland

Leaning on gas

Northern Ireland’s small grid is transitioning at a different tempo compared to the rest of the UK. But it has a similar reliance on natural gas.

Investment in renewables and battery storage assets is not keeping pace with retirement of ageing thermal assets. Meanwhile, a spate of unplanned forced generator outages has tightened margins at times.

There were two “system alerts” in Northern Ireland during summer 2024 due to “insufficient levels of dispatchable generation, and these challenges will remain ahead of the winter period,” System Operator Northern Ireland (SONI) said in its 2024-25 winter outlook.

Margins this winter should be adequate to meet system demand, SONI said. But only if there is no disruption to gas supply from both the Moffat terminal and the Corrib gas field.

*Unplanned outages are on the rise in Northern Ireland. Chart: SONI*

Network not working

At the same time, transmission bottlenecks hinder the ability to balance supply and demand. The island of Ireland operates under an integrated single electricity market (SEM), which spans the two separate jurisdictions. Dispatch is managed through an All-Island balancing market (BM) process.

In theory, participation in the SEM and BM allows Northern Ireland to smooth out localised imbalances across a larger geographic region. In reality, the single market’s ability to do so is hindered by the ‘tie line’, which is the only operational north-south interconnector. It has a transmission capacity of just around 450 MW.

This already presents a bottleneck. Wholesale prices in the GB power market are generally lower than in the SEM, so Northern Ireland imports cheap power from Scotland. But this cheap power cannot always be transmitted onwards to meet demand in the Republic.

The result is increasing ‘dispatch down’ orders to curtail excess generation in Northern Ireland, and ‘dispatch up’ orders to fire up thermal plant on the other side of the boundary. Increasing renewable market share is likely to aggravate these issues, according to market sources.

Widening the bottleneck

A second high-capacity line, known as the North South 400 kV Interconnector, is under development. With a capacity of 1,500 MW, it is expected to alleviate the worst of the constraints when it comes online in 2027.

Bolstering interconnection across the island is a prerequisite to achieving renewable energy targets. Both the Republic of Ireland and Northern Ireland have targets to achieve 80% generation from renewables by 2030.

The targets are not an all-island ambition. Instead, both jurisdictions must achieve them independently. This presents co-ordination challenges for Eirgrid and SONI, the two system operators on either side of the north-south border.

If the Republic exceeds its target, this does not offset the need for Northern Ireland to deploy more renewables to hit its own 80% goal. There is a risk of a rush to build, resulting in overcapacity across the SEM in the 2030s. Expanding transmission capacity is vital to managing that risk.

No route to market

In both cases the 2030 targets are challenging and likely to be missed. They will be achieved sooner or later, but in the meantime the bigger challenge is to accelerate investment and mobilise supply chains.

For a variety of reasons, deployment of renewable energy and storage assets has been held back across the island.

A spate of judicial reviews has choked off the pipeline of shovel-ready projects in the Republic. Meanwhile, the lack of a functioning support regime has hindered the route to market for wind farms in the North.

The Northern Ireland Renewables Obligation (NIRO) closed to new projects in 2017. The NIRO operated just like the Renewables Obligation (RO) in the GB market, but when it was wound down it was not replaced by an alternative support regime.

The UK government introduced Contracts for Difference (CfDs) for the GB market, which underpinned a major investment drive in wind, solar and other renewable projects. But failure to do the same in Northern Ireland denied projects a government-backed route to market. This left them to negotiate corporate power purchase agreements (cPPAs) with utility buyers.

*The Elginny wind farm in County Antrim. Photo: Shutterstock*

Corporate neighbour

There is a healthy market for corporate PPAs in the Republic of Ireland, thanks to two policies: Dublin’s promotion of a supportive fiscal environment for large power-hungry tech companies, and the Renewable Energy Support Scheme (RESS).

Data centres could account for as much as one-third of grid load in the Republic within the next couple of years, according to some estimates. These structurally short corporate energy buyers must offer cPPA prices that are attractive compared to the alternative: competing in Dublin’s RESS auctions.

Northern Ireland, by contrast, has neither of these conditions, meaning corporate buyers have greater leverage when negotiating cPPA deals with wind or solar developers.

The upshot is a “vanilla” cPPA market in the north that lacks depth and liquidity, according to one renewables project investor, speaking on condition of anonymity. As a result, Northern Ireland is enduring an almost decade-long investment hiatus and there’s a pent-up backlog of projects.

*Volcanic hexagonal basalt columns of Giant’s Causeway in Northern Ireland. Photo: Shutterstock*

New dawn awaits

That is set to change with the rollout of a new subsidy system. Northern Ireland’s RESS will introduce a new voluntary CfD-style support mechanism to procure generation via auctions starting in 2025-26, for delivery from 2027 onwards.

The NI CfD will support onshore renewables and wave and tidal, but not offshore wind. The latter is held back by a lack of a robust offshore regulatory framework for development in Northern Irish waters.

Still, the prospect of an index-linked route to market is reviving investor interest in the region’s considerable onshore wind resource.

“I’ve spoken to a wide range of investors who used to tell me they couldn’t develop renewables projects in Northern Ireland. Now, they are changing their tune,” said Steph Unsworth, senior research associate at Aurora Energy Research.

The Northern Irish CfD is expected to procure in the region of 1,000-1,500 TWh of annual generation every one or two years. But it must be carefully designed to work successfully in the regional context.

“Northern Ireland is a much smaller market than GB. You don’t have lots of people bidding so certain things need to happen to ensure auction competitiveness given the very small number of players in the market,” Unsworth told E-FWD.

Paying a premium

Ireland’s small size and geographic position at the western peripheries of Europe make it more expensive to build infrastructure than on the continent. Supply chains are tight and domestic manufacturing capability is extremely limited, requiring components to be imported from further afield.

Furthermore, the planning process is more onerous and securing a grid connection is more expensive across the island of Ireland. In combination, these factors will necessitate a premium in the Northern Irish CfD compared to the GB equivalent, Unsworth said.

The Republic of Ireland is already paying a premium to attract investment. The country’s most recent onshore renewable energy auction cleared at an average price of €104.76 per MWh for solar PV and €90.47 per MWh for onshore wind – equivalent to £87.67 per MWh and £75.71 per MWh respectively.

In the GB market, the AR6 auction last month cleared at £50 per MWh (in 2012 prices) for onshore wind and solar. In today’s money, that’s closer to £70 per MWh, meaning the Republic of Ireland is paying a premium of 25% for solar and 8% for onshore wind power compared to Great Britain.

Since many of the factors that inflate costs are common across the island of Ireland, it is conceivable that the Northern Irish CfD will not need to pay a premium above the Republic, Unsworth said. And if the region can move more quickly than its southern neighbour — a big ‘if’, to be sure — it might even steal a march on renewable market share in the SEM.

*Steph Unsworth. Photo: Aurora Energy Research*

The long shadow of Brexit

Northern Ireland is still grappling with complications arising from the UK’s departure from the European Union — not least the decoupling of the SEM from the EU’s internal energy market.

The SEM used to be coupled with the mainland EU network via the Moyle interconnector between Northern Ireland and Scotland, and East-West Interconnector (EWIC) between the Republic or Ireland and Wales. This allowed Irish electricity to be traded through centralised platforms across all interconnectors in the EU.

Those interconnectors are physically still in place, but Brexit severed the SEM’s coupling with the EU market. It also meant that EU network codes are no longer mandatory for Great Britain and Northern Ireland.

“There is the potential for bilateral agreements to allow for trading, but this is still being negotiated,” said Lisa Foley, principal consultant at Cornwall Insight. “What this means is that since Brexit, the SEM has not been coupled to mainland Europe and our day ahead wholesale power markets are operated decoupled for the majority of the time.”

Northern Ireland remains part of SEM through the post-Brexit Trade and Co-operation Agreement (TCA), which “makes the regulatory challenges of an All Island market less complex”. However, “the complexity is in the actual integration of these market codes into the SEM rules,” Foley said.

A new interconnector from Ireland to France — the Celtic Interconnector — is in development stage and due to become operational before the end of the decade.

Coupling up

When that happens, the SEM will once again be coupled to the EU electricity market and will take part in the coupled trading algorithms within it, Foley explained.

“Including this in the design of SEM is a significant piece of work and will require industry, system operators, market operator and regulators in Ireland and Northern Ireland working together to implement the requirements in advance of the operational go live date,” she added.

It won’t be a silver bullet, however. The energy aspects of the TCA will terminate on June 30, 2026, although this may be extended to March 31, 2028 at the latest. “With issues such as trade over interconnectors and an enduring agreement with respect to the electricity sector in Northern Ireland, the UK is likely to be involved in energy negotiations with the EU for some time longer,” according to Norton Rose Fulbright.

GoO riddance

Brexit also disadvantaged Northern Ireland versus the Republic with regards to Guarantees of Origin (GoOs): certificates issued to prove that a specific amount of electricity was produced from renewable sources.

GoOs are essential for corporate energy buyers who want to claim their electricity is ‘green’. Thanks to Brexit, renewable electricity from the UK (including Northern Ireland) is no longer recognised by the EU for GoOs unless specific bilateral agreements are in place.

The Republic of Ireland can still source GoOs from across the EU GoO system. However, Northern Ireland faces restrictions because the UK’s GoO certificates are no longer recognised in the EU market without specific agreements.

Corporations in Northern Ireland may face challenges in using UK-issued GoOs to meet EU-based renewable energy claims. Similarly, tech firms in the Republic can’t easily use GoOs issued in Northern Ireland to meet their clean energy targets, making NI wind and solar projects less attractive compared to sites in the Republic.

The storage question

Howsoever the energy transition pans out across Ireland, the island’s integrated single electricity market will need more storage – and lots of it. Sadly, the SEM is acting as a barrier, rather than enabler, to deployment of battery energy storage systems (BESS).

BESS asset operators may participate in wholesale power trading, but the existing process for doing so is excessively onerous thanks to antiquated IT systems and control processes. There are also constraints on BESS participation in the balancing market.

“Batteries must ring up the control desk at Eirgrid or SONI when they want to charge,” explains Unsworth of Aurora.

“BESS can be given an order by the TSO through the centralised redispatch … However, they can’t submit bids and offers and participate outside of SO [System Operator] flagged actions. BESS need to be treated more like other assets that can participate automatically. Right now we are seeing batteries doing energy arbitrage in other markets. This doesn’t really happen in Ireland,” she said.

Regulatory shift for BESS

Lack of full access to the SEM wholesale and balancing markets is not a complete show-stopper to BESS investments in Northern Ireland. Storage assets can capture lucrative revenues from ancillary services via the DS3 programme.

DS3, which stands for Delivering a Secure, Sustainable Electricity System, was introduced to incentivise provision of frequency response, ramping, reactive power, inertia, and voltage control.

“The frequency response services FFR, POR, SOR, TOR1, and TOR2, the so-called ‘Fast Five’ services, currently form the bulk of battery storage revenues,” Unsworth wrote in a recent commentary for Aurora.

DS3 availability payments are made based on administratively set scalars and tariffs. But this regulated approach is not compliant with EU guidelines, so Northern Ireland is switching to a new market-based framework for ancillary services procurement.

While details remain sketchy at this stage, the shift away from administrative tariffs “definitely adds risk to battery projects,” Unsworth said. “There’s going to have to be more active management of assets.”

That said, the current regulated arrangement is not risk-free. When costs exceed the DS3 expenditure cap, the system operators can and do cut tariffs unilaterally and with little warning.

The largest component of the DS3 tariff was slashed in September, resulting in an estimated reduction to the internal rate of return (IRR) for a newbuild one-hour battery by 860 basis points, according to Aurora. While this was not the worst-case outcome, further overspend is anticipated in 2025 and 2026, meaning extra tariff cuts are to be expected.

A challenging path ahead

The energy transition in Northern Ireland faces unique challenges compared to the rest of the UK. While the region has achieved important milestones like the closure of its last coal plant, its shift to cleaner power sources now faces a complex web of obstacles.

Overcoming the post-Brexit regulatory and infrastructure hurdles will be essential if the region is to keep pace with the rest of the UK and Ireland in the race to net zero while keeping the lights on. Timely introduction of the Northern Irish CfD would help allay fears of further stagnation in the country’s renewables market.

Without a functioning government in Stormont, there is no guarantee that Northern Ireland will be able to implement the right mix of policies to secure investment. The path ahead is challenging to say the least.

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