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.

CMS Breakfast Seminar: Co-location of storage and renewable generation

Introduction

The intermittent generation profile of wind and solar farms is one of the main challenges of the energy transition. How do you store green electricity when the sun is shining, and the wind is blowing so it can be used later in the evening or at night?

Stand-alone battery energy storage systems (BESS) try to address this by storing electricity when prices are low (i.e. the sun shines and the wind blows) and selling it later.

Another approach is locating batteries at solar or wind farms and optimising the amount of electricity imported or exported into the grid.

CMS London organised a seminar with industry experts to discuss the challenges and opportunities for the business model of co-located projects.

Panelists

The panel was made up of:

• Charlie Websper, Senior Director, DIF Capital Partners

• Ralph Johnson, Head of UK Business Development, Habitat Energy

• Hannah Staab, Head of Strategy, Natural Power

• Rosalind Smith-Maxwell, Director, Quinbrook Infrastructure Partners

Insights they shared

Why co-location

Co-locating a battery and a solar PV farm has some direct benefits:

• Both projects can share grid connection costs, and having a battery on-site reduces the imbalance charges for the solar generator.

• An on-site BESS can store excess production and help deal with active network management problems and grid constraints.

• The load factor for UK solar PV is only about 10% to 14%, leaving enough room for a battery.

Project setup

Almost all co-located projects in the UK couple the BESS with the solar farm on the AC (alternating current) side of the inverters, requiring one set of inverters for the solar farm and a second set for the battery. This reduces points of failure (i.e. one broken inverter doesn’t take down your entire project) and allows the installation of separate electricity meters.

Coupling BESS on the DC (direct current) side is trickier. You save costs, as you only need half the number of inverters, though this is partially negated by the fact that DC/DC inverters are more expensive than their DC/AC counterparts.

Another factor to consider is that it is harder for DC-coupled batteries to participate in the ancillary services market.

All panellists agreed that DC-coupled batteries only make sense if you significantly oversize the PV farm and use the battery to avoid clipping losses in the current market environment.

As for the contractual setup, having one SPV owning the battery and the solar PV generator is the preferred option. This removes the need for grid-sharing agreements, and the solar cash flow can be used to support the operation of the battery.

Revenue model

Combining a solar generator with a battery gives you a firmer generation profile, which means you can achieve prices above the solar capture prices.

The priority use of the export connection is given to the solar PV generator. This impacts the arbitrage trading of the battery only minimally due to the low load factor of solar PV.

However, optimising a co-located battery is more labour-intensive than a stand-alone BESS project, and you can only achieve 60% of the FFR revenue and 70% of the capacity market payments.

Asset owners, therefore, often use one optimiser to manage the solar farm and the battery, allowing the creation of revenue stacks:

• Solar: submit part of the capacity in CfD auctions while operating the rest on a merchant basis

• BESS: participate in the ancillary services market and pursue price arbitrage through physical or financial trading

Over the next few years, there will be significant changes to the revenue model.

• Ancillary markets are becoming saturated. Arbitrage trading is becoming more and more critical for battery projects.

• The current indication is that the GB power market might be split into different price zones as part of the REMA process.

Financing

Lenders are still uncomfortable taking significant merchant risk exposure and prefer fixed-price contracts. For example, DIF closed a financing for a co-located project earlier this year and had to sign up to a 10-year floor price contract for the battery. This leaves significant arbitrage upside potential on the table.

Another aspect lenders worry about is the interface risk between the ICP, the solar EPC contractor and the battery OEM.

Retrofitting

As grid connection dates for new projects tend to be several years in the future, retrofitting older PV plants offers the opportunity to deploy capital in the shorter term if you can get import capacity. But it is only happening slowly, despite the first project in the UK being completed in 2017.

One panellist highlighted that the battery needs a minimum size of 20MW to make this economically attractive.

Another panellist mentioned that sellers are asking buyers to value the potential for a battery retrofit in recent sales processes for operating solar PV plants.

Differences with US markets

Due to its size and market structure, the US market is seen as more advanced than the UK market.

The West Coast market’s extreme duck curve incentivises longer duration storage (4 hours) for load shifting. In Nevada, for example, evening prices from 18:00 to 21:00 hours are six times higher than power prices at noon.

And US corporate off-takers increasingly demand renewable energy 24/7, incentivising co-location to shift part of the daytime production into evening hours.

Challenges for co-located projects

The seminar concluded with the panellists discussing what challenges they see for co-located projects in the UK.

• Lenders need to get more comfortable with merchant risk.

• Investors need clarity on the potential shift to zonal pricing and other topics in the REMA process.

• Larger price differences between daytime and peak-demand times would encourage the installation of longer-duration storage, as seen in the US markets.

• Increasing costs and falling power prices have reduced the profit margins of batteries.

• BESS have a different risk profile than a solar farm, which can lead to higher costs (e.g. a higher fire risk, and therefore insurance is more expensive).

My thoughts

Co-locating batteries and solar farms allows for a more efficient use of the grid connection and is the next stepping stone towards an electricity network that offers renewable electricity 24/7.

Retrofitting operational solar farms with batteries can be a stop-gap measure to help us reach the net zero targets. But this only works if the existing grid connection allows for large enough electricity import.

When comparing the UK and US markets, you notice that intraday price differences here are not significant enough to make load shifting economical.

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.