Wood Mackenzie London Renewables Briefing 2024

Wood Mackenzie’s annual Renewables Briefing took place on 30 April 2024 in London. They are a consultancy that provides data, analytics, insight, and events around the energy transition.

Events like these are good opportunities to gain insights into the industry’s state, the participants’ moods, and what they expect in the future.

Below are some key takeaways from the event.

European Power Markets (presented by Dan Eager)

Electricity demand keeps falling due to improved efficiencies and demand destruction caused by the Ukraine war. At the same time, more intermittent electricity generators are being commissioned, replacing old coal, gas, and nuclear power plants.

This leads to an increasing number of times of „oversupply“ and hours with negative energy prices. The chart below shows the cumulative hours with negative pricing for several European countries.

Source: Wood Mackenzie

These negative prices open up new arbitrage trading possibilities for energy storage projects (charge the battery when the prices are negative and discharge it when the prices are high).

Wood Mackenzie forecasts that baseload electricity prices will stabilise in the range of €40/MWh (Nordics) to €60/MWh (Germany, Italy, UK) after 2030. However, the capture rates for solar and wind projects without energy storage will continue decreasing.

We have probably reached a turning point for corporate PPA prices, as several projects are no longer viable and will not be built. This will reduce supply and increase prices again.

Electricity demand in Germany will keep falling until 2030, before the full effect of electrification kicks in.

Energy Storage (presented by Anna Damani)

Governments and TSOs support the deployment of more energy storage as more and more intermittent generators are coming online. There is no unified support mechanism in Europe. The slide below shows the systems on a country-by-country basis.

Source: Wood Mackenzie

Wood Mackenzie forecasts the installed storage capacity (excluding pumped hydro) to grow from 9GW to 100GW by 2033, with the UK (20%), Italy (17%) and Germany (15%) becoming the most significant markets.

Ancillary markets are lucrative, but only for first movers and some countries, like the UK, already have an oversupply. This leaves energy trading and government tenders as the most important revenue component going forward.

Currently, the upper limit for economically viable lithium-ion batteries lies around 5 to 6 hours. Beyond that, we will need new technologies to achieve true long-term energy storage.

Long-duration energy storage capacity will only grow significantly from 2030 onwards and will need subsidies to be built.

My thoughts

The days of making money by building a pure wind or solar project are over. Too much intermittent generation is being built, and simply bolting some energy storage solution onto your generator is only a temporary fix. The big winners will be IPPs and strategic investors who hold large portfolios with multiple generation technologies and large energy storage capacities. They can offer (almost) baseload green power levels that are no longer tied to a single asset.

Second REMA consultation: Highlights

The second consultation of the Review of Electricity Market Arrangements (REMA) is open until 07 May 2024. It is part of a wider reform process in the UK to adapt the electricity system for a net-zero future.

The REMA process tries to find solutions for four fundamental problems:

• How do you address that the best wind resources are in the north, but most of the demand is in the south?

• How do you prevent price manipulations?

• How do you make sure that we have sufficient generation capacity?

• How should the government support new renewable energy projects?

Better locational price signals

Most demand is in the south of England, where there is limited room for new solar farms and onshore wind farms are effectively banned. As the existing transmission network has limited transport capacity, we can’t “ship” enough electricity from Scotland to England on windy days. This means that wind farms in the north have to curtail their production while expensive gas-fired power plants in the south are being used to meet the demand.

To solve this problem, you either need to:

1. build more electricity generation capacity in the south of England or

2. reduce the electricity demand through more efficiency or

3. you encourage companies to move their facilities to the north.

This can only be achieved if the electricity in the south is more expensive than in the north.

REMA is considering two alternatives:

1. Split the electricity market into different price zones along the transmission bottlenecks OR

2. Reform the existing transmission charges system by either

3. Using the existing ofgem network charges reform

4. Reviewing the transmission network access arrangements

5. Expanding constraint management

6. Optimising the use of cross-zonal interconnectors.

Central vs Self-Dispatch

Currently, it is up to each generator to decide how much electricity they want to feed into the grid/sell on the market. This system is called self-dispatch and is commonly used in Europe. This system can lead to two problems:

1. Too much electricity is produced, and prices fall or become negative.

2. Generators withhold their production to create an artificial shortage, and when prices spike, they start selling their production.

In some countries (like parts of the USA), central agencies decide who can sell what amounts of electricity at any given time. This is called a central dispatch system.

While the UK government is exploring the option to switch to a central dispatch system, it is unlikely to be introduced because of the high implementation costs. A reform of the existing self-dispatch system is more likely.

Capacity Market reform

The capacity market is another tool for the network operators to ensure that enough generation capacity is available at all times. Contracts are awarded through auctions.

As part of the reform process, the government is considering to introduce new minimum criteria in each auction:

• minimum capacity target per region

• minimum capacity target per technology

These auctions could be used to support the build-out of new generation in regions of high electricity demand and to support new technologies.

CfD Reform

The Contract for Difference (CfD) scheme has become an important tool to support the energy transition. The government wants to future-proof it to include options for new technologies and for retrofitting older wind or solar plants (re-powering).

The options under consideration are:

• Pay generators on deemed generation instead of the actual produced electricity. This would allow producers to reduce their output in times of oversupply without losing income.

• Pay generators a lower fixed amount for the capacity (per MW) and let them sell the electricity on the open market.

• Limit how many MW per plant can be submitted in the CfD auctions. The idea behind this proposal is to provide asset owners with a minimum amount of certain revenue while encouraging them at the same time to sell the rest of the production on the open electricity market.

• Review the formula for the calculation of the reference price.

Provide your feedback

If any of the abovementioned areas impact you or your business model, I encourage you to submit your feedback to the Department for Energy Security and Net Zero (DESNEZ) by 7 May 2024. You have the rare chance to influence the design of the electricity market for years to come.

REMA: Nodal or Zonal Pricing?

REMA and the coming changes of the UK electricity market

The energy transition brings significant changes that require rethinking the rules of the electricity market. That is why the UK government launched the Review of Electricity Market Arrangements (REMA) consultation process.

The UK currently faces a problem: Scottish wind parks are producing the cheapest renewable energy. But the majority of the demand sits in Southern England. And there are not enough transmission lines to transport all the electricity produced in Scotland to England. To match supply and demand, you must curtail (limit) the amount of electricity produced in the North and use expensive fossil fuel generators in the South.

Therefore, one question being asked is whether having a single electricity price across the whole of Great Britain (Northern Ireland is in a joint market with the Republic of Ireland) is still the best option in this situation.

What is Locational Pricing?

Currently, people pay the same price for each electron whether it is being produced in Kent, in the Midlands or off the Scottish coast.

A result of REMA could be that Great Britain gets split into multiple markets to send stronger price signals and to balance the market better:

• If you have lots of demand in one market, prices would increase, incentivising people to consume less or at different times.

• If a lot of electricity is produced in another market, prices would fall (oversupply), and generators would be incentivised to reduce production.

Over the long term, energy-intensive industries would ideally move into markets with cheaper prices. And investors would build more generators in markets with high prices.

Electricity markets can be organised around Nodes or Zones.

What is Nodal Pricing?

According to ofgem (the UK regulator), a node is a single point in the network where wires/cables meet. This could be the substation where a generator connects to the local network. Or where the local electricity lines connect to the wider transmission network.

And each of these connection points would have its own electricity price.

Several countries/regions worldwide use this model, notably Texas, California, New England, Singapore and New Zealand.

The problem with Nodal pricing is that you create tens of thousands of tiny “markets” across the network. And each market has only a few generators and consumers. Therefore, the normal price-setting mechanism through the market doesn’t work in this case.

As a result, you need to introduce a central dispatch system and abolish the intra-day market. The sole responsibility for balancing supply and demand lies with the system operator in a nodal pricing model.

What is Zonal Pricing?

Price zones can be drawn up in different ways. Often, they follow geographic dividing lines or bottlenecks in the transmission network (interconnections between regions).

Within Europe, Norway, Sweden, Denmark and Italy have already split their countries into different price zones.

Source: Wikipedia

As long as the zones are big enough (i.e. enough market participants), electricity prices tend to be more stable and predictable than nodal prices. Consumers and generators can help the system operator balance the network through an intra-day market.

However, you will need some form of locational hedge or financial instrument for PPAs if the generator and the consumer are not in the same price zone.

Closing thoughts

The next government communication regarding REMA is due before Christmas, and industry insiders expect that we will get some additional information regarding the potential introduction of locational pricing.

It would take several years to introduce nodal or zonal electricity markets. Not only would you need to update all the laws and regulations, but also test the system thoroughly before switching away from the current model. We can’t afford disruptions in the flow of electricity.

It will not be a quick fix for the current problems of congested transmission lines and long waiting times for new grid connections.

But splitting the British market into several price zones would create enough pressure to incentivise :

• the build-out of new transmission lines (because people in the South will be angry with politicians due to higher prices) and

• drive the adoption of demand-side responses (smart meters, load shifting, etc.) from consumers.

One open question will be how to integrate legacy PPAs into this new market. The previously agreed price could be significantly lower or higher than a future locational price. Who will carry the financial burden or benefit from these old contracts?

Why is Italy the new hot BESS market?

Source: Pexel

BESS = Battery Energy Storage System

TLDR (Too Long, Didn’t Read)

Italy is an attractive market if you enter early and pick the right locations (Sicily, Sardinia, south of the mainland).

Recent Deal Activity

The UK market has long been seen as the most active and advanced of all European countries regarding energy storage. The relatively high penetration of intermittent renewable energy and limited interconnection due to the island location created a thriving market.

But recently, a string of deals and announcements came out of Italy. Here are just some examples:

• Enel secured 1GW in capacity market contracts from grid operator Trena in 2022 and is replacing retiring fossil fuel plants with batteries in Sardinia, using the existing grid connection.

• Aura Power is working on a 1GW plus pipeline in Italy.

• Matrix Renewables has partnered with others to develop 1.5GW of projects.

• Eku Energy partnered with a local developer to create a 1GW pipeline.

What does the Italian market look like?

The country has about 7.7GW of pumped hydro storage projects, mainly located in the Piedmont and Lombardy regions, and energy storage plants are exempt from grid charges.

The country is split into seven price zones with limited interconnection between them. But contrary to the Nordic markets, only generators get paid different prices for their production. Consumers are being charged an average price that is the same across the country.

Italian Price Zones (Source: Terna)

Power Generators and Storage Operators can participate in the wholesale market or the capacity market.

Source: Aurora Energy Research

The national grid operator Trena is running capacity market auctions, with some contracts being awarded to battery projects.

The frequency response market has only been open to thermal generators in the past, but some pilot projects are being developed to open the service to batteries.

The Regulatory Authority for Energy, Networks and the Environment (Autorità di Regolazione per Energia Reti e Ambiente or ARERA) approved new criteria and conditions for large-scale energy storage capacity on 6 June 2023, which will allow Trena to run large-scale energy storage auctions

A consultation is running to get industry feedback on the design of the auction system, and the first auctions are expected for later this year or early next year.

A separate auction mechanism is being developed for long-duration energy storage (LDES) projects with a duration of 6 hours or more. It is expected that the contracts will be awarded for the entire operating life of the assets.

In return, participants must offer projects that can time-shift load and provide ancillary services.

What are Italy’s targets regarding energy storage?

Italy has a national energy plan (PNIEC) and targets a renewable share of 55% by 2030 in the electricity sector.

Based on this target, Terna expects that 15GW of total energy storage will be needed by 2030, of which 9GW needs to be LDES with a duration of at least 8 hours.

What can BESS bring to the table in Italy?

Close to 50% of electricity generated comes from imported natural gas. The build-out of renewable energy generators can reduce this dependency on imports. However, it will lead to grid constraints and a higher price volatility in the intraday markets.

And this where energy storage plants can help with the energy transition:

1. They can help stabilise the grid by absorbing excess electricity production during peak production times and releasing it back onto the grid when the demand picks up in the morning and evening.

2. There is less need to build new interconnections between the different price regions. Batteries can store electricity until it can be sent to another region.

3. Intraday price differences offer BESS operators the chance for arbitrage (buying electricity when it is cheap and selling it for a higher price later on).

Will Italy become the next UK for BESS?

The first large-scale projects have been granted planning permissions, and many investors are rushing into the market in a land grab.

In a PV Magazine interview, Milan-based management consultancy MBS Consulting estimated that trading in the spot market could cover 60% to 65% of the project capital expenditure (CapEx). The remaining 35% to 40% of revenue would need to come from ancillary services.

Italy’s different price zones and their limited interconnectivity will shape the Italian need for energy storage.

1. The two island markets (Sicily and Sardinia) favour a large-scale deployment of energy storage, as electricity cannot easily be exported to or imported from the mainland.

2. The large-scale deployment of solar energy plants in the country’s south will lead to excess generation during the daytime, requiring energy storage to shift the production to the evening peak demand.

These constraints will increase the need for a growing capacity market in these regions, opening up higher revenue opportunities for investors and making Italy an attractive market to be in.

Closing thoughts

Italy has a considerable potential and a significant need for energy storage. But picking the right location is crucial, with the south and the island markets offering more favourable market conditions than the country’s north.

Investors that enter the market will have an advantage over latecomers. As we can see in the UK market, more and more projects compete for the same ancillary service contracts, driving down prices. The earlier your project is ready, the fewer competitors you have.