Alun Rees, UK Director of Regulation, Public Affairs, CSR and ESG, ENGIE

Published in Utility Week

Of all the phrases ubiquitous to the REMA debate, “we would not start from here” is one that everyone seems to agree on. But what does that really mean? What can today’s policymakers learn from what their predecessors got right, and what they got wrong?

To begin on a positive note: what would we do all over again? It was a good move to “drain the pool” and introduce decentralised, bilateral trading in electricity to replicate the efficiency of other commodity markets. End-user prices fell after NETA was activated in 2001. An array of forward products emerged, allowing buyers and sellers to lock-in prices ahead of time. Whilst forwards liquidity has become an increasing challenge of late, this is not the fault of fundamental market design principles, which remain robust.

On the support scheme side, the Renewables Obligation (RO) and Contract for Difference (CfD) have been world leading and broadly successful policies. They have unlocked £billions of investment in wind and solar, helping the UK to become first major economy to halve its emissions.

What has been missing? Probably the biggest regret is that grid build has not kept pace with renewables, driving constraint costs. Constraint costs have in turn set the zonal hare running and skewed perceptions around the reliability and value of wind generation.

Allied to insufficient grid build, the first-come-first-served queuing system was never suitable to meet ambitious clean power targets. It is anachronistic at best that the locational investment signal changes after a plant has been built. Variable transmission charges are inappropriate when renewable investors lock-in revenues via long-term CfDs and/or PPAs.

What lessons can we take? The main lessons from grid build, connections and transmission charging is that we need incentives across the energy system to be pulling in the same direction.

Another lesson we can learn from REMA’s predecessor EMR – which gave us the CfD – is that market designers should try very hard to understand the short, medium and long-term impacts of their creations. In 2014 the Government characterised “Stage 4” of EMR – occurring from the “late 2020s” as “competition without intervention”. In other words, the Government envisaged no more need for CfDs from the late 2020s onwards. Clearly, we have not reached Stage 4 of EMR, and may not ever. CfDs will be needed for the foreseeable future and may become a permanent support for new investments in renewable electricity generation.

How can we apply this lesson of “seek to understand one’s creation” to the national vs zonal debate?

In the short term, any decision to break GB wholesale market into zones will hinder rather than help the Government’s Clean Power 2030 mission. The uncertainty will hinder power generation infrastructure investors of all types, but those in the north will be hit by a perfect storm. They will face two flawed and unpredictable locational costs at the same time: high and rising transmission costs and the spectre of lower future wholesale prices. These were only ever meant to be substitutes. Neither is helpful on its own; together they are a disaster.

If “going zonal” would be bad in the short term, any decision to go zonal ahead of AR7 with the current degree of zonal definition would not really be helpful compared to a decision to go zonal afterwards. Any detail left unspecified – of which there would be plenty – would need to be priced. Uncertainty is risk and risk has a price.

In the medium term, much is disputed. But recent analysis commissioned by both sides of the national-zonal debate predicts wholesale electricity price increases in at least the southern half of England and Wales. Zones of increased price would include the Government’s growth corridor running from Oxford to Cambridge.

And what of the longer term?

The fundamental context in which REMA finds itself is the replacement of plant with variable fuel and emission costs (e.g. natural gas and CO₂) by plant with zero variable costs (e.g. wind, sun). The paradox of this transition is that the business case for new CfD-free renewables is precisely the need for marginal capacity predictably setting the electricity price at their variable generation costs. Or opportunity costs in case of storage or demand response.

Intuitively, higher wholesale power prices in the south (driven by unabated gas) suggest potential opportunity for CfD-free renewables. But in practice the opportunity is subject to multiple risks: planning risk; grid-build risk; cannibalisation risk. Perhaps most importantly volume risk: it is windiest away from current demand centres.

The larger and more stable the market or bidding zone, the greater the variety and number of power buyers and sellers. This agglomeration effect makes the value of electricity more predictable, and easier to construct a business case for a CfD-free plant.

To date, UK policymakers have not visibly grappled with the question as to whether there should be a long term future for new renewables being constructed off the back of input fuel costs. However, any breakup of the GB wholesale market into zones risks answering the question accidentally, and ushering in an era of “everywhere CfDs”. “Everywhere CfDs” will accelerate cost recovery away from the wholesale market to consumer levies, undermining the benefits case for zonal. Zonal thus becomes a self-unfulfilling prophecy.

We at ENGIE believe that the Government should foster an environment in which there is a continued place for unsupported renewables alongside CfDs. To this end, the GB “bidding zone” should be kept as big as possible for as long as possible. A wide variety of buyers and sellers should also help enable green molecules and flexibility options to perhaps in time replace unabated gas as the “price setter”.

Instead of breaking the single GB market into zones, we believe that the Government should:

1. Turbo charge grid build. NESO’s CP 2030 advice suggests that this would reduce constraints costs from around £6.5bn to around £1bn in 2030 in the “New Dispatch” scenario. The equivalent effect in the “Further Flex and Renewables” scenario would be a reduction from around £8bn to less than £2bn.
2. Introduce a robust locational investment signal through spatial planning and fundamental overhaul of the transmission charging regime. This could entail new fixed charges that align with the centralised plan for the system, that endure for the life of the asset.
3. Enable new and existing consumers in constrained zones to predictably save on their bills by offering cheaper electricity at times when generators would otherwise be curtailed. Such “local constraint markets” should include demand-turn-up to make the most of wind, and demand-turn-down to avoid turning up gas.

We believe that our plan best learns lessons from the past, and shows understanding of power market fundamentals. On the other hand, “going zonal” puts us at greatest risk of saying to each other in the 2040s: “we would not start from here”.

And if the Government does intend to answer the question of the future of CfD-free investments through REMA, it should be made clear and explicit, and not become an accident of history.

About ENGIE

ENGIE is a major player in the energy transition, whose purpose is to accelerate the transition towards a carbon-neutral economy. With 98,000 employees in 30 countries, the Group covers the entire energy value chain, from production to infrastructures and sales. ENGIE combines complementary activities: renewable electricity and green gas production, flexibility assets (notably batteries), gas and electricity transmission and distribution networks, local energy infrastructures (heating and cooling networks) and the supply of energy to individuals, local authorities and businesses. Every year, ENGIE invests more than €10 billion to drive forward the energy transition and achieve its net-zero carbon goal by 2045.

About ENGIE in the UK

In the UK, with 1,300 employees, ENGIE owns and operates a large portfolio of renewable and flexible storage assets, across electrons and molecules, including one of the largest pumped-storage hydro plants in Europe. Our JV company Ocean Winds is one of the largest offshore wind generators in Scotland with 950MW of operating capacity and 882MW in construction. We supply +17,000 business customers with electricity and gas and accompany them in their decarbonisation journey. Over its 20 years of operations in the UK, ENGIE has unlocked billions of pounds into the country’s energy transition.

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