December 31

Energy market outlook – what can we expect in 2024? – Watt-Logic

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ENB Pub Note: Excellent Summary from Watt-Logic. I would add some wild items happening in the global oil and gas markets. OPEC, and OPEC + have had a major loss of control over the oil pricing market. The weaponization of the US Dollar against the world has opened the “Dark or Ghost Fleet”, accelerated the move away from the petrodollar and changed all of the global financial models around energy. With countries trading energy in their own currencies, the OPEC and sanctions are simply “Mind over Matter” as Putin would say. “I don’t mind because the US and Biden don’t matter.”

The past couple of years have been dominated by concerns over energy prices, particularly gas. However, gas prices have fallen significantly from their highs of summer 2022, and while they are still double the long-term average prior to autumn 2021, they are probably going to remain at broadly this level for some time. Significant further reductions seem unlikely at this time, and while there may be seasonal reductions, the market looks to have found a new level, at least until new LNG supplies come onstream in 2026. The risks are more that the market will tighten in the meantime, pushing prices higher, or that geopolitical risks crystalise, affecting supplies.

This means that absent a new supply pushing prices higher, outright gas and electricity prices are unlikely to have the same high profile that they had over the past two years, although other aspects of energy pricing are likely to be in focus, as I describe below.

Re-assessing energy economics

This has started in 2023. The failure of so many wind tenders and the need to reduce expensive energy subsidies are likely to drive further thinking into energy economics. Whether that is positive or not remains to be seen – policy-makers struggle to let go of favoured narratives (renewables are cheap) and in some EU countries, subsidies are welcomed more warmly than in others. Subsidies are necessary to stimulate immature markets, but should be phased out once those markets reach maturity. That has manifestly not happened in the wind sector – indeed, subsidies are increasing despite a quarter of a century of market stimulation.

Policy-makers are recognising that one way out of this difficulty is to reduce demand, and there continue to be half-hearted attempts to reduce energy waste in the built environment. However, this is a hard-to-solve problem and there’s no real prospect of any country really seizing on the challenge at a time when budgets are constrained.

Governments want to make energy cheaper, but are failing to recognise that their own policies are making energy more expensive. Energy systems built on intermittent renewables are certain to be more expensive than those based on more reliable technologies, for the simple reason that double the amount of capacity will need to be built in order to ensure security of supply. It ought to be self-evident that this is the case, irrespective of the short-run marginal operating costs of wind and solar. In addition to extra capacity, whether that is in the form of generation or storage, additional grid infrastructure is needed to connect all of this capacity, and balancing costs rise when both supply and demand become highly variable. It’s past time that policy-makers recognised these realities, and it is to be hope that the failed wind tenders and turbine-maker losses of 2023 will be a catalyst for this re-evaluation.

The UK Government has said it is updating its LCOE framework – I challenged the Secretary of State at a recent Policy Exchange event to make it fully cost comparative, including de-commissioning costs for all technologies. I sense that there is a growing understanding that current metrics are not working – even Lazard has expanded its LCOE to include some measure of firmness – but whether these will go far enough remains to be seen. I suspect 2024 will be the start but the steps will be small.

Focus on supply chains

In 2023 we started to be aware that the delivery of net zero ambitions would require huge amounts of resources: financial, human and material. And that access to those materials may not be straight-forward. In 2023, the increased costs of materials had a significant impact on the cost of new generation, particularly in the renewables sector, but across the energy value chain there will be a huge increase in the amounts of minerals required.

According to the IEA, an offshore wind turbine requires nine times more minerals than a comparable gas-fired power plant, and an EV uses six times more critical minerals than an ICE vehicle. It’s not just power grids that require large amounts of copper – wind, solar hydro and geothermal generation all rely on copper as well as nickel, silver and rare earths. Nuclear power plants depend on uranium for fuel, while nickel alloys are a key component in their cooling systems as well as being used inside the pressure vessel. EVs rely on a range of critical minerals for battery components, and also require rare earths for motor design and copper for wiring.

Far and away the largest source of new mineral demand will come from grid infrastructure, such as power lines and transformers. Taken together, the need for critical minerals will double between 2020 and 2040 based on the stated policies of governments, and quadruple in the IEA’s Sustainable Development Scenario. In both scenarios, EVs and battery storage account for about half of the mineral demand growth from clean energy technologies over the next two decades – mineral demand from EVs and batteries is predicted to grow tenfold in the Stated Policy Scenario and over 30 times in the Sustainable Development Scenario by 2040. By weight, mineral demand in 2040 is expected to be dominated by graphite, copper and nickel, with lithium experiencing the fastest growth rate – increasing by over 40 times in the Sustainable Development Scenario. The shift towards lower cobalt chemistries for batteries will limit growth in cobalt demand, as it is displaced by nickel.

A lot more mining is going to be needed to deliver these requirements, but with a 20-year lead time for opening a new copper mine, this is a non-trivial challenge. I will be addressing this topic in a series of upcoming posts, highlighting the scale of the issue.

Hydrogen crunch time

The time for making decisions on hydrogen is rapidly approaching. The approach taken varies across different countries, with some countries pursuing a vision of nationwide and even international hydrogen pipelines while others expect local industrial clusters to be more likely. Hydrogen pipelines seem more like a pipe dream once the physics of hydrogen are taken into account, and the huge losses incurred simply moving the gas around in a pipeline system. EU hydrogen targets already look set to be missed, with investment for these projects thin on the ground as the Inflation Reduction Act sucks capital into US projects.

The governments of Germany, France and Denmark have the highest ambitions for 2030, however, as this article states, ambitions and targets do not necessarily translate into meaningful action with very few projects reaching Final Investment Decisions. These will need to come in 2024 if 2030 targets have any hope of being met. As things stand, the business case for clean hydrogen is far from clear, with the economics of fossil fuels remaining better in most if not all cases. Of course this means that subsidies will be necessary, but how much money is available for yet more subsidies in already fiscally constrained countries remains to be seen.

Hydrogen for heat, particularly in the domestic sector, suffered a blow in the UK with both local hydrogen trials having been cancelled due to public opposition to the schemes. Hydrogen for high temperature industrial heating applications probably does make sense, but there are questions about how it can be produced. While the current narrative is all about using surplus renewable generation, this is unlikely to be practical in many cases – the use of small nuclear reactors would make more sense, but those won’t be deployed until well into the 2030s.

All of which makes me believe that the 2030s are the sensible timeframe for the emergence of any kind of hydrogen economy. But 2030 is rapidly approaching, so the plans and investment decisions will need to start being made if these projects are to be realised. The next couple or years will be crucial if hydrogen is to emerge as a real piece of the de-carbonisation solution, or remain a niche application.

Nuclear renaissance continues

The renewed interest in nuclear power is likely to continue into 2024 with more countries announcing more new projects. The main challenges will be delivering both these projects and the uranium to fuel them, with supply chain constraints and lack of skilled workers in various parts of the industry being significant limiting factors. We are also likely to see more countries delaying the closure of legacy reactors, the re-opening of more shuttered reactors in Japan, and, depending on the success of Holtec’s bid to re-open Palisades, attempts to re-open other closed reactors elsewhere (providing that progress on de-commissioning was limited).

However, progress on small modular reactors is unlikely to be significant in 2024. Some projects continue to move forward and perhaps we may see some further design certifications, but nothing in the West is close to being built.

With the first EPRs and AP-1000s now open, there may be pressure to build more, however France is already looking to the next generation EPR2. KEPCO’s APR-1400, with its seventh and eighth reactors soon to open, is far in the lead, and the smart money would be on the Koreans teaming up with other countries for the wider deployment of its technology. Its eight-year build time and established supply chains are also highly attractive, and buyers would do well to contract multiple units with local workforce training by Korean experts being part of the package.

New nuclear projects may also benefit from some revision of energy economics. An all-in technology comparison including de-commissioning costs is likely to favour nuclear above renewable generation. However, onerous regulatory regimes continue to stifle the development of the market. Governments should push for greater trusted country regulatory collaboration in 2024 to facilitate the smoother development of future nuclear pipelines.

Security of supply will remain on the agenda

Concerns over security of supply are here to stay, and have several dimensions. Access to fuel in respect of geo-political risks is now in focus, along with an increased awareness of infrastructure vulnerabilities after an attack this year on the Balticconnector pipe between Finland and Estonia. Countries should develop better infrastructure monitoring and emergency plans in the event of disruption to key infrastructure.

The impact of energy policy on security of supply is also not going away, particularly in the US, where the issues appear to be more acute than in Europe. However, the UK faces similar challenges, and is likely to face a supply crunch as this decade progresses. Indeed, unless something changes, we will face periods with no nuclear power on the GB system by the end of the decade since Hinkley Point C is now unlikely to open before 2030. With all the AGRs due to close by March 2028, only Sizewell B would be left, and it cannot run indefinitely without maintenance and re-fuelling outages.

The increased reliance on intermittent renewables creates real security of supply risks in the absence of long duration storage, and since such storage (with the exception of hydro, which cannot be deployed everywhere) has yet to be invented, many countries face similar threats. The use of interconnectors to mitigate these risks will likely prove of limited benefit since the connected markets are likely to share similar weather and similar energy mixes. The US is building more gas fired generation to deal with this risk – other countries, particularly the UK are likely to have to follow suit.

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Source: Watt-Logic

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