October has been another exciting month in the world of battery energy storage! And we’ve had a super busy month here at Modo. We’ve made improvements to the platform, we’ve updated Signal, and we’ve written loads of new Phase articles. With that in mind, here are the top five most popular Modo articles from last month:
5. REMA: reinventing markets - a special episode of Modo: The Podcast
What we said:
In this special, all-Modo episode of the podcast, Ed Porter (Chief Commercial Officer) takes over as guest host - to chat with Robyn Lucas (Chief Analytics Officer) and Alex Done (Head of Research) about all things REMA. Over the course of the conversation, they discuss:
- The changes being considered for wholesale energy markets - at national, zonal, and nodal levels.
- How current dispatch arrangements might change in the future.
- The evolving support mechanisms for renewables and capacity procurement.
- How the UK will support longer-duration energy storage.
- And evolution vs. revolution - how do we want the industry to look in a post-REMA world?
4. Constraint management on the transmission system - what are the costs?
What we said:
The graph below shows the cost of managing constraints across the six main boundaries, from April 2017 to September 2022.
- The impact of recent gas price hikes can be seen in the difference in costs from the year ending September 2021, and those from the year ending September 2022.
- From October 2020 to September 2021, the ESO spent £0.76b managing transmission constraints. From October 2021 to September 2022, it spent £2.0b. This represents a 165% year-on-year increase in costs.
- Also, costs associated with managing constraints have increased significantly in the last five years - as more distributed renewable generation has come online.
As renewables make up a larger proportion of Great Britain’s energy stack, the challenges of managing and maintaining a reliable transmission network increase. Constraint management costs have risen over the last few years. However, market forces also play a significant role: there has been a dramatic rise in costs recently due to high gas and electricity prices.
To manage constraints in the future, significant network reinforcements will be needed, as well as improved dispatch mechanisms that better incorporate potential constraints into price signals.
3. The Energy Prices Bill: how will it affect battery energy storage?
What we said:
The ‘Cost-Plus Revenue Limit’ is a way to break the link between high gas prices and the revenues received by low-carbon generators within the current power market structure. It will cover all non-Contracts for Difference low-carbon generation, which includes solar, wind, nuclear, and biomass. As proposed, the Cost-Plus Revenue Limit could be in place until 2027.
The generators targeted by the Cost-Plus Revenue Limit have not seen the same increase in operational costs as some fossil-fuelled plants, such as CCGTs. Therefore they are likely to have seen an increase in profits during the crisis. In some instances, they may also receive government subsidies on top of these increased power prices (through the Renewable Obligation scheme for example). This argument has faced some criticism, as many generators have secured long-term fixed prices for their export and so have not seen any increase in profits during the crisis.
In the form currently proposed, the Cost-Plus Revenue Limit does not cover battery energy storage as an asset class - and so will not directly affect stand-alone battery energy storage revenues. Additionally, it should not affect wholesale prices. Therefore, it should have no impact on battery energy storage trading revenues.
It is unclear how the Cost-Plus Revenue Limit could impact co-located storage. This will depend on how generators are defined within the final policy. In the worst-case scenario, co-located storage discharging into high-price periods of the day could see significant revenue clawback. This would be a counter-productive outcome, as it would decrease the incentive for energy storage investment - which is critical to bringing down future energy costs.
2. National Grid ESO’s Winter Outlook: Part One and Part Two
What we said:
National Grid ESO’s Winter Outlook scenarios all assume that imports via the North Sea Link interconnector will be available when needed, to deliver up to 1.2 GW. This would primarily come from Norwegian hydro plants. However, in September, the Norwegian Parliament discussed limiting exports in the event of low reservoir levels - to preserve domestic energy reserves for winter, following extended periods of low rainfall.
The graph below shows the current reservoir levels on both a national and regional level in Norway, in addition to historical ranges observed from 2000-2021.
- Reservoir levels across the whole of Norway are currently sat at 69%, relative to an all-time low of 62% over the past 20 years.
- Low reservoir levels in the NO2 bidding zone (where the North Sea Link connects to Norway) are currently sitting around their 20-year minimum. Due to network constraints between North and South Norway, this could increase the likelihood of limits being imposed on exports.
- We are yet to hear if/when the Norwegian Parliament will introduce export limits on the North Sea Link. Any limits would cause a significant reduction in Great Britain’s import capacities, relative to the Winter Outlook scenarios. Therefore, this is something to watch as we move into winter.
1. Co-location explained
What we said:
The stand-alone battery storage fleet is currently performing extremely well. With this in mind, why is there interest in co-location?
- Increasing utilization of available grid connections. Delays in being granted access to the grid (some sites are being quoted connection dates for 2037!) are turning available connection capacity into the industry equivalent of gold dust. Storage has low average utilization of its grid connection, as do many generation types. For example, both storage and solar may only utilize their grid connection on average 10-15% of the time. Co-locating therefore makes more efficient use of one of the most valuable aspects of a project.
- Managing project risk. Both generation and storage projects face long-term price cannibalization risks. Combining multiple technologies (and associated business models) helps diversify revenues and reduce risk.
- Sharing costs. Locating the two assets on the same site reduces both the CAPEX and OPEX of the project compared to two standalone systems. With connection costs increasing significantly, this alone can make or break a business case.
- Expanding revenue opportunities. With the right technology and/or operational strategy, co-located storage can deliver new revenue opportunities (again reducing long-term revenue risk). For example, a direct current (DC) coupled storage asset can charge from solar energy otherwise curtailed at the inverter, to later sell onto the wholesale market.
This pipeline of co-located solar and storage is bringing innovations across policy, finance, and technology. For example, changes to the Contracts for Difference scheme to facilitate the co-location of storage, as well as all-in-one offtake agreements have been introduced to simplify financing. For more on the co-location of solar and storage, check out this episode of the Modo podcast.
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