Each retail market intervention seems logical in isolation, but piled one on top of each other are taking the market further and further from the original premise. Have I accurately recalled everything important from the past 20 years?

If xkcd did nerdy energy retail policy comics:

With apologies to xkcd, and thanks to Nano Banana and ChatGPT, but not Copilot.

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It is a truth universally acknowledged, that a renewables dominated electricity market, must be in want of cost-reflective pricing.

However little known the feelings or views of such a man may be on his first connecting to a network, this truth is so well fixed in the minds of the regulator that his flexibility is considered as the rightful property of some one or other of the stakeholders.

(with apologies to Jane Austen)

Decarbonisation, digitalisation, decentralisation and democratisation.

For years, the 4 Ds have been the rallying cry of the energy transition. Retail consumers will have the same access as the “big guys” to own generation and access markets. But as these examples show, when you strip away the middleman, you also strip away the shock absorbers.

Texas, Spain and Norway have all been held up as leading examples for dynamic pricing. Did consumers benefit? How did regulation change after a price shock? And does it continue today, after retail consumers were directly exposed to the raw, unbuffered volatility of wholesale markets.

Griddy & Texas Electricity (Winter Storm Uri)

In 2021, Texas consumers using the provider Griddy were billed the real-time wholesale price of electricity. While this usually saved them money, Winter Storm Uri caused wholesale prices to skyrocket from $50/MWh to the regulatory cap of $9,000/MWh.

• Beneficial? No. Some customers received bills for $10,000+ for a few days of power.

• Regulated? Yes. In May 2021, Texas passed SB 3, which effectively banned wholesale-indexed electricity plans for residential customers.

• Continues Today? No. Griddy went bankrupt, and retail wholesale-index plans are now illegal in Texas for households.

Spain’s PVPC Energy Tariff (2022 Crisis)

Until recently, Spain’s default electricity tariff (PVPC) was directly linked to the hourly wholesale market. When the 2022 crisis hit, even though the government capped the price of gas for electricity generation, Spanish households on the default rate saw their bills double while those on fixed tariffs did not.

• Beneficial? Great during high-renewables days (near-zero prices); terrible during geopolitical crises.

• Regulated? Yes. In 2024, Spain reformed the PVPC to include a “basket” of long-term futures prices to dampen the hourly volatility.

• Continues Today? In a modified, “buffered” form.

Norway’s Norgespris (2024 Dunkelflaute)

Norway is still the leading country for households on dynamic tariffs, but numbers have fallen dramatically. ACER’s 2024 Retail Market Monitoring Report had it at 93%. But after price spikes in December 2024, the government introduced the Norgespris in October 2025, 48% of households have opted in to the regulated price, and in the 3 zones with the most volatile prices, 63% of households covering 72% of demand have opted in to the tariff.

• Beneficial? Dynamic tariffs are favourable in zones will low volatility.

• Regulated? No, but the introduction of Norgespris offers consumers a discounted fixed option.

• Continues Today? Yes, but consumers are overwhelmingly opting for Norgespris.

It’s not just in energy that retail consumers have been granted access to wholesale markets. Can the industry learn from other sectors?

The Dot-com IPO boom (Late 90s)

In the late 90s, retail investors were lured into the IPO craze. Investment banks often “spun” hot IPO shares to favoured clients, but retail investors bought the “pop” on the first day of trading at wholesale-market prices that had no basis in fundamentals.

• Beneficial? Short-term “paper” wealth for some; catastrophic for most.

• Regulated? Yes. The Sarbanes-Oxley Act (2002) and later FINRA Rule 5130 restricted how IPO shares are allocated to prevent “spinning” and price manipulation.

• Continues Today? Partially. Modern “Pre-IPO” platforms (like EquityZen) exist, but they are generally restricted to Accredited Investors to avoid another retail wipeout.

Subprime Adjustable-Rate Mortgages (2008)

ARMs exposed homeowners directly to the wholesale LIBOR (interest rate) market. When the Fed raised rates and the wholesale cost of borrowing increased, retail monthly payments doubled or tripled. House prices crashed, with borrowers owing more than their property was worth.

• Beneficial? Short-term (low “teaser” rates); long-term (foreclosure).

• Regulated? Yes. The Dodd-Frank Act and the “Ability to Repay” rule made it much harder to sell these “exploding” loans to unqualified buyers.

• Continues Today? Yes, but they are much more strictly regulated and require significant “stress-testing” of the borrower.

It seems such a simple solution - exposing consumers to the true cost of electricity will influence their behaviour and reduce the flexibility needed by the electricity system. And cutting out the middlemen, the investors and traders who profit from the energy markets, will reduce consumer costs.

Cost-reflective pricing has become the mantra for regulators and policy-makers, retailers and aggregators alike.

But everywhere that dynamic electricity tariffs have been popular, that popularity has collapsed each time consumers have been faced with market volatility. Examples from the financial sector concur - exposing retail customers to wholesale prices often results in them bearing risks they are ill equipped to bear.

Low generation and high demand caused the German Day Ahead price for Thursday evening spike to €936 per megawatt-hour (MWh), with Intraday prices even higher. With renewables producing barely 10 GW, Germany had to take drastic measures to balance supply and demand, ramping up fossil generation and rely on imports from neighbouring countries, pulling prices up across Europe.

Internal market for electricity

European markets have become more connected, both physically, with interconnectors allowing power to flow between countries, and through the internal market for electricity facilitating cross-border trade.

So when spot market prices in Germany hit €936/MWh for the evening of December 12, prices in Norway peaked at €898/MWh. Although 93% of households at the time had dynamic tariffs, consumers are protected by the Strømstøtte, a subsidy introduced in 2021. Covering 90% of costs when the hourly price exceeds 75 øre/kWh, the impact of a price above 1000 øre/kWh can’t be ignored.

The Zonal question

Unlike Germany, Norway is split into multiple price zones. Despite an abundance of hydropower, transmission constraints prevent power flowing from North to South.

The usual price differential between the zones is such that Hashrate Index, a website that “provides metrics, analysis, and research that demystify the Bitcoin network and Bitcoin mining industry” describes both countries having only two zones - cheap electricity in the north, and expensive electricity in the South.

When Southern Norway reached their peak, households in Northern Norway were only paying €10/MWh, ninety times lower than the market price in the South.

Germany has similar long-standing grid constraints, but a single market price for the whole country. It deals with the resulting congestion through redispatch - instructing generators in constrained areas to reduce generation, and those nearer demand to turn up. Annual redispatch costs are around €3bn.

Splitting the country into multiple zones, as recommended by Entso-E’s Bidding Zone Review and the European Commission’s Joint Research Centre, is expected to lead to lower prices in the north, and higher prices in the south.

And had this been the case last December, it might have prevented the collapse of the Norwegian government. For that’s what happened in January, with the Center Party withdrawing from the coalition due to disagreements over the adoption of EU energy laws.

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Although then a minority government, the Labour Party introduced in June the Norgespris - a new support scheme for household energy costs. Offering a fixed price of 40 øre/kWh, not just protection against extreme prices, it is available to any household or holiday home in the country.

Although not an EU member state, as a member of the European Economic Area (EEA), Norway must adopt most EU laws and get State Aid approval for subsidies. However, as the Norgespris support households not companies, and applies to all residential consumers, it has been argues that approval is not needed.

In regions where prices are high, the Norgespris provides much more support than the Strømstøtte. It is no surprise that when applications opened ahead of the October launch, more than 700,000 households (26%) and 140,000 holiday homes (39%) opted for the Norgespris.

The latest figures show 936,000 households (36%) and 172,000 holiday homes (48%) have opted in. But unsurprisingly, regional take up has not been evenly split:

In Southern Norway (NO2) 58 % of the 630,679 have signed up. In Eastern Norway (NO1) 43 % and Western Norway (NO5) 34 %.

But in Central Norway (NO3), only 814 households, 0.2 % of the potential have taken the offer. And in Northern Norway (NO4), too few to even register a number.

Will this affect prices on a cold, dark and still winter evening? Households in Southern Norway will be able to heat their homes without worrying about the cost. But in Southern Sweden, equally affected last December, there are worries that demand from Norway will pull prices up further

.The Swedish preference is for Germany to also split into different price zones. The German government is expected to reject the proposal. But it’s hard to see how the single market for electricity can expose consumers to such different price signals and incentives, and remain coherent across national borders and physical constraints.

What can we learn from this?

1. What happens in Germany doesn’t stay in Germany. Decisions on market design in one country have implications for other countries and a mix of market designs is unlikely to be sustainable.

2. Consumers are rational - up to a point. They accept exposure to market volatility - unless it becomes too volatile. But insulating them from volatility risks incentivising inappropriate behaviour.

3. Customers with fixed prices need other signals to incentivise flexibility, and customers exposed to real time pricing need circuit breakers.

The assessment found that splitting the Germany–Luxembourg Bidding Zone yields a higher positive socio-economic welfare change compared to the status quo. The highest positive benefit for the 2025 target year was the split into five bidding zones (DE5). At €339 million, however, this value is less than 1% of the simulated system costs in the CE region.

The input data used in the BZR is outdated (mostly created in 2019 for the 2025 target year), the misalignment between the 2025 target year and a potential implementation date around 2030, and the necessity to thoroughly assess potential negative impacts on market liquidity, transaction costs, and the balancing market.

A lot has changed since 2019. Not least COVID19, the invasion of Ukraine, and the responses that protected consumers from high prices and incentivised accelerated investment in renewable generation.

Into the debate comes the recently published JRC report on Locational Price Signals in Europe. Looking further into the future, and based on more recent data, it suggests that Locational Marginal Pricing is essential for maintaining security of supply at the lowest cost in future low-carbon electricity systems.

Assessing two approaches, the ambitious zonal Multi Split scenario would split the European market into 101 zones and achieve substantial savings of €10–37 Bn in 2040.

The more granular Locational scenario could reduce the total system cost by €26–61 billion annually by 2040 compared to the Status Quo.

Regardless of the market structure, where any change is unlikely to be implemented before the 2030s, the imperative is to stop incentivising and rewarding developers to build in the wrong place.

While any change to the current bidding zones or introduction of nodal pricing introduces uncertainty for investors, curtailment costs will continue to rise and the debate will return. Even the status quo can only give investor certainty at a cost to consumers.

And the modelling found that introducing Locational Investment Signals alone delivers system cost savings of €12–29 Bn in 2040 even when implemented within the Status Quo zonal structure.

Developers should still have the right to build wind farms where it is windy, where the cost of land is lower, and where they can get planning permission. But when that imposes costs on the wider energy system, recognising those costs and reflecting “their expected impact on the grid” in any decision would be a least regrets approach regardless of the future zonal structure.

For a 30 minute discussion of the issues raised, listen to NotebookLM’s podcast based on the ENTSO-E and JRC reports.

The concept is simple, and aligns with the idea of a fractal grid - my choice of twitter handle a decade ago, and the title of this Substack.

At every level of the grid, matching supply and demand locally minimises the need to expand infrastructure to the next level of the grid. Instead of a single market at a notional balancing point, markets give price signals that enable optimisation of each level.

We are inevitably heading towards that state, optimising for self-consumption and dynamic tariffs within the home, and with DSO flexibility markets emerging to manage local congestion.

But the cost of grid infrastructure is still recovered from consumers based on their imports from licensed suppliers. And not just grid costs, but also levies on final consumption including Feed in Tariffs, Renewables Obligation, Contracts for Difference and Capacity Markets. Later this year, the Nuclear Regulated Asset Base levy will hit consumer bills. npower Business Solutions predicts these will make up 75% of a customer’s total invoice by the start of the next decade.

The License Except Supply model that saves customers up to 30% of their bill does so by avoiding all of these costs, not just the reduction in costs and losses directly resulting matching locally. And those avoided costs are recovered from other consumers.

One of Energy local’s partner suppliers, Octopus Energy, recognises this conflict: “This Energy Local scheme is in effect using the grid’s infrastructure without paying for it”. This will lead to “less cover of transmission and distribution costs – which might be a challenge at scale”.

Early trials involving Emergent Energy were facilitated by Ofgem’s regulatory sandbox, while the 5MW limit on generator capacity restricted the approach to small installations.

High transaction costs meant that the approach had limited applications beyond shared housing and related companies, but a recent modification to the Balancing and Settlement Code, P442, facilitates matching “where a portion should be exempt, and another portion should be licensable”.

The emergence of platforms like tem and UrbanChain facilitate the matching of generation to business customers at a previously unimaginable scale.

Generators and consumers should benefit from license exempt supply that matches locally, but only to the extent that this actually reduces system costs, rather than avoiding them.

Matching supply and demand locally at every level of the grid will be a feature of the future energy system. And occupants of a block of flats should have the same opportunity to save using the solar panels on their rooftop as the owner of a detached house.

But when the mechanism to facilitate this starts to looks more like the wholesale market, and is commercialised on a scale where households see the impact on their bills, the need to reform network charging and final consumption levies will become urgent.

Local balancing will only be sustainable as a market within the market, not as a market outside the market.

Between the campsite and the village lies Necton Onshore Substation. Already a substantial site connecting to the Dudgeon offshore wind farm, it is being expanded by 22,000m2 to accommodate power coming from the Vanguard and Boreas projects, acquired by RWE from Vattenfall.

It's not the only substation in the region facing protests against expansion plans, with a converter station at Saxmundham for the Lionlink connection to offshore wind farms and and a new substation at Friston for the Sealink HVDC cable to Kent.

Another protest group, Suffolk Energy Action Solutions, is challenging the creation of energy superhubs being developed in East Anglia as part of an integrated North Sea grid.

Further down the coast lies Sizewell nuclear power station, where consumers will soon start to pay for the construction of Sizewell C through the Regulated Asset Base scheme. Although the cost of construction has doubled from the first assessment, it may be another decade before power is generated. Next to the National Trust owned Dunwich Heath, local protests have been organised by Stop Sizewell C.

But it's the solar farms and big batteries clustering around transmission substations that seem to generate the fiercest responses. These solar farms, largely hidden behind hedgerows, are facing a range of protests that don’t seem to affect the 350 intensive pig and poultry farms in Norfolk and Suffolk, many close to towns and visible from main roads.

Villages around the Sunnica solar farm have been plastered with Say No to Sunnica placards and attracting MPs to protest walks https://www.bbc.co.uk/news/uk-england-suffolk-60812728. Even the County Council is getting involved, and also objecting to EcoPower plans.

Although it's easy to find more examples of protest groups, such as Block East Pye Solar organising against developments, I've recently noticed something new. More and more coverage is highlighting the plight of individual small businesses affected by construction work at solar farms. Ranging from kennels to The Museum of Technology, rural businesses owners are becoming a more personal objection than the protest groups.

Despite the gas import terminal at Bacton (Norfolk, not the Bacton on Suffolk) much of the region is off the gas grid and suffers from a lack of energy infrastructure. And at this time of year, many homes receive deliveries of oil, wood and even coal to get through the winter.

Net Zero won't be achieved without a social license, but objecting to everything risks leaving the region shivering in the dark.

Highlighting analysis from Digiconomist that it “now consumes the same amount of electricity every year as Denmark - 33TWh” and forecasting “at that rate of growth, it will consume as much electricity as the US in 2019” the article fed into the narrative that the technology would dominate electricity consumption.

Much like the narrative around data centres in the early days of the internet, or, indeed, AI today.

Bitcoin mining very quickly developed from a decentralised, democratic endeavour, to one defined by the amount of computing power, and the cost of the electricity it requires, to play the lottery of finding a hash of the block’s header that meets the target.

It’s called “Proof of work”, but is only akin to work in the way that repeatedly hitting a tee shot on a 400 yard hole until you get a hole-in-one could be considered professional golf.

Even then, it estimated that “60% of a Bitcoin miner’s income would be spent on operational costs, including electricity bills.”

By 2021, the BBC was reporting University of Cambridge Bitcoin Energy Consumption Index figures showing that “Bitcoin consumes 'more electricity than Argentina'“

Not that the second bar in the chart is the USA, with about 30 times the electricity consumption of Argentina (121 TWh).

Using the same source data, but somewhat confusingly aggregating consumption for 2020 and 2021, a United Nations University report highlighted electricity consumption for Bitcoin mining in the top ten countries:

Its analysis of the data found Bitcoin’s consumption “enough to rank it 27th among nations, trumping the likes of Pakistan.” Note that when the BBC placed Bitcoin in the top 30, Pakistan was nowhere to be seen. Either the BBC, University of Cambridge or United Nations University is incorrect, or electricity consumption in Pakistan grew quicker than Bitcoin in 2021.

The report, published in 2023, focuses on China and the dominance of coal in the generation mix supplying Bitcoin miners. But the finding that offsetting China’s emissions due to Bitcoin would require planting 2 billion trees was somewhat superseded by China’s clampdown on Bitcoin, shutting 90% of its mining capacity.

Much of this was load was transferred to Kazakhstan and Texas with their “cheap and abundant energy supply”. Using CBECI estimates that the US share of Bitcoin mining rose from 3.4% in January 2020 to 37.8% in January 2022 (the latest figures available), it consumed 0.6% to 2.3% of all United States electricity demand in 2023.

The growth in Bitcoin mining was causing such concern in the US that in 2024 the Energy Information Administration announced an emergency collection of data from cryptocurrency mining operations, only to be discontinued before even starting “after a lawsuit filed by Bitcoin data center operators”.

With the price of Bitcoin reaching new highs in 2024, The University of Lille reported its “electricity consumption comparable to that of Poland” and “0.4% of annual global demand”. Significant, but nowhere near the WEF forecasts.

And since then, both Digiconomist’s estimate of Bitcoin energy consumption and CBECI’s have plateaued around 170 TWh, while computing power continues to rise due to increasing efficiency of mining hardware.

So mining companies facing a difficult market are diversifying into AI. Instead of hash rates, mining CEOs were “talking about how to monetize megawatts” at the recent SALT conference.

“At five cents per kilowatt hour, it currently costs around $60,000 to mine a single bitcoin. At a bitcoin price of $115,000, that means half the revenue is consumed by power alone.” Not dissimilar to the 60% reported by the WEF.

But when “Power – Not Hashrate – Becomes Bitcoin Mining’s ‘Real Currency’” it puts mining into competition not just from AI, but households and businesses. Despite rolling blackouts in rural areas, Bitcoin mining pays just 3c/kWh in Ethiopia. Having invited miners in to earn foreign currency, with demand projected to reach a third of the country’s supply this year, Ethiopian Electric Power “intends to discontinue existing agreements”.

Although we might not be reading about Bitcoin’s energy consumption in comparison to countries any time soon, or that its electricity consumption will get anywhere the early forecasts, the work may finally be put to use. Mining company Canaan launched “Bitcoin Mining Heaters for Home and Personal Use” at CES in January.

This was intended to be a hot take on Orsted's decision to cancel the Hornsea 4 project, having been awarded a Contract for Difference (CfD) in the UK’s auction just last year. Then came the German offshore wind auction with no bids. Then Orsted announced a rights issue, blaming the US market. Then came the start of the UK's latest CfD auction, with calls for 8GW of offshore wind to meet the 2030 target.2

It feels blasphemous to say this, but with the cost of living crisis and current political environment, should we commit consumers to paying for 8GW of offshore wind in 20 year inflation linked contracts?

Especially if those contracts can be rebid, cancelled, or revised if costs turn against developers, but bill payers have no recourse against developers installing fewer, larger turbines, or delaying the start of the subsidy to benefit from high wholesale prices.

UK consumers are already paying £200/MWh for the 3GW of offshore wind awarded in early CfD contracts to meet the 2020 renewables target. With the AR7 auction critical to meeting the Clean Power 2030 target, are we in danger of repeating ourselves?

Although the recent confirmation of Orsted’s decision to abandon Hornsea 4 was clearly commercially rational (especially in light of their €8bn rights issue), and contractually permissible, was it morally acceptable?

Having won funding for 2.4GW just last year in the Allocation Round 6 Contracts for Difference auction (AR6), the cancellation is a blow to the UK’s clean energy ambitions. And it will have an impact on the public perception of net zero, consumer costs, and rivals’ bidding strategies in upcoming auctions?

The reasons given by Orsted for cancelling the project were:

• increase of supply chain costs

• higher interest rates

• increase in the risk to construct and operate Hornsea 4 on the planned timeline

But with the objective for CfDs to appropriately balance the risks between Value for Money (VfM), bill affordability and investor confidence, it’s hard to think of any auction that has been an unqualified success:

• Eye-watering high prices in AR1

• Delayed start to AR2 projects to benefit from high prices

• AR3 projects delayed due to supply chain issues

• Cancellation of Boreas and rebid of AR4 projects into AR6

• No bids for offshore wind in AR5

• Cancellation of Hornsea 4 from AR6

Should we be rethinking the role of offshore wind in the 2030 renewables target, whether CFDs are the appropriate mechanism to support such large, long term projects, and perhaps the 2030 target itself?

One of the dubious benefits of having spent 20 years in the energy markets is when you recognise patterns from history playing out all over again. Contracts for Difference themselves were the solution to the flaws of earlier support schemes.

Early years - the Renewables Obligation

From its introduction in 2002 to the final closure to new generation in 2017, the RO successfully supported the early growth of solar and onshore wind generation. Some might say too successful, with a perception that support costs were growing out of control.

The scheme required electricity retailers to submit RO certificates in proportion to the electricity supplied to their customers. This obligation was amended annually on a rising trajectory towards the 2020 target. Certificates were awarded to renewable generators, who could trade them to supplement the revenue earned from the wholesale market. Retailers could either buy certificates or pay a buy-out price, which rises with inflation each year..

With the buy-out fund being recycled back to the retailers submitting certificates, any shortfall in renewable generation would increase the value of a certificate. This market mechanism meant that the feed in premium would adjust to the growth of renewable generation along the trajectory, and generators would remain exposed to wholesale market prices.

All renewable generation received 1 ROC per MWh when the scheme was launched, resulting in higher support for technologies with lower costs. When banding was introduced in 2009, offshore wind and solar PV were considered emerging technologies and would receive 2 ROCs per MWh. In the 2023/24 year, offshore wind supported by ROCs generated 23.35TWh, 30% of the total generation under the scheme, but received over 40% of certificates.

Perhaps foreseeing negative wholesale prices, developers felt that the quantity-based support scheme, which exposed generators to market volatility, did not provide the level of revenue certainty needed for the growing scale of offshore wind farms.

And with costs of the scheme rising, in 2011 the government introduced the Levy Control Framework to place an absolute cap on consumer spend on renewable generation. This coincided with, and later became part of the framework of, Electricity Market Reform (EMR).

Transition - FIDER contracts

Implemented under the Energy Act (2013), EMR introduced Contracts for Difference to support renewable generation with a 15-year inflation linked price insulated from market volatility.

Although the Act enabled generators to choose between CFDs from their introduction in 2014 and RO up to the closure in 2017, enduring implementation of CFDs would require secondary legislation.

To enable investment decisions before the legislation was passed, bilateral contracts were awarded under the Final Investment Decision Enabling for Renewables process. And although they were meant to bridge the gap between the RO and introduction of CFDs, contracts were awarded less than 5 months before the first biennial Allocation Round.

The FIDER contracts were awarded without competition to 8 projects. Due for commercial operation by April 2019, they would directly contribute to the UK's legally binding 2020 renewable energy target. With strike prices set by the government, the 5 offshore wind projects with combined capacity of 3.14 GW are now receiving £200/MWh for their generation.

A NAO review found that the “decision may provide higher returns to contractors than needed to secure the investment and also limits the amount of remaining budget.”3

Enduring solution - Contracts for Difference

And so to the enduring CFD, a two-way contract where the difference between the contracted strike price and the market reference price is paid to or by the generator, providing developers with direct protection from wholesale electricity market volatility.

The strike price is indexed over a 15-year period, with the objective of lowering the cost of capital for developers while protecting consumers from the combination of high support costs while wholesale prices are high.

The auctions, known as Allocation Rounds, were initially every 2 years, although from Allocation Round 5 onward are held annually. None has unquestionably managed “to appropriately balance the risks between Value for Money (VfM), bill affordability and investor confidence”.

Allocation Round 1

Although the introduction of competition resulted in strike prices 18% below the cap, auction prices for 2017/18 delivery were £119.89/MWh and for 2018/19 £114.39/MWh. Back of the envelope calculations suggest current revenues are not so different to what they would be receiving under the RO. Not the saving CfDs were meant to deliver.

Allocation Round 2

The second Allocation Round was hailed as a success, with prices dropping to £74.75/MWh and £57.50/MWh for projects starting 2021/22 and 2022/23.

Attributing this cost reduction to increased competition among developers, improvements in the UK offshore wind supply chain, and the adoption of larger, more efficient turbines, offshore wind was the dominant technology.

But when wholesale prices spiked following the Russian invasion of Ukraine. Generating power from June 2021, Moray East did not start its CfD until 2024.

Although this is “within the terms set by the CfD process” the intention of allowing deferred start dates of the cfd was to allow for unavoidable delays in planning and construction.

At the time, commentators argued that CFDs are "an effective tool for encouraging investment in renewables, whilst guarding against excess profits, and rising consumer prices." They warned against windfall taxes or controlling these excess returns as "counterproductive to the UK’s decarbonisation efforts".

Moray East is estimated to have profited £647m from high wholesale prices during the delay to the start of their CFD. The project is currently under investigation by Ofgem for excessive curtailment bids.

Even before this, a 2019 review found that “The current structure has led to a decline in investment for established technologies like Onshore wind and Solar-PV.”

Allocation Round 3

Prices continued to tumble, down to £39.650/MWh for the 2023/24 delivery year and £41.611/MWh for 2024/25. Offshore wind secured a substantial 5.47 GW of contracts, representing 95% of the total capacity awarded in this round.

The Dogger Bank projects have been beset by delays due to weather and supply chain issues, while Forthwind was the first CfD backed offshore wind project to be terminated.

Allocation Round 4

The even lower prices are still hailed as a success, claiming cost savings from installing fewer, but larger wind turbines. But although only Norfolk Boreas has been terminated, all of the other winning projects rebid capacity into Allocation Round 6 at a higher price.

This is within the laws of the scheme, but not the spirit of the game. In a pay-as-clear auction, the winning bid sets the price for all projects. Without the terminated project and rebid capacity, would the clearing price for the remaining projects have been more sustainable? Would other projects have won instead?

Allocation Round 5

Given the “success” of the previous rounds, the maximum strike price was set by the Government at £44/MWh. On the back of a sharp rise in costs following Russia’s invasion of Ukraine, there was not a single bid for offshore wind. The reaction to the lack of bids from offshore wind was almost unanimous, with commentators arguing for the government to reassess scheme price caps, and even to reopen this auction with higher prices.

Allocation Round 6

With the move to annual auctions, rather than every two years, the opportunity to bid came around again, with a maximum strike price for offshore wind projects increased by 66% to £73/MWh. Developers reducing the capacity of existing CfD projects and rebidding into the auction represented the majority of offshore wind projects in Allocation Round 6.

And with the cancellation of Hornsea 4, the projects that rebid at a higher price are now the majority of offshore wind capacity in the auction. Other investment decisions, whether for generation or storage, are made based on the contracted CfD pipeline . Terminating and rebidding capacity changes those assumptions. Would other projects have gone ahead, knowing what we know now?

Allocation Round 7

The latest auction has now opened, with some changes. Capacity awarded in previous auctions is not permitted to rebid. Would Hornsea 4 have been cancelled if it could have rebid?

Offshore wind projects that have not yet received planning consent are allowed to bid. While this may “attract more bidders to the auction and improve competition”, it may also increase the risk that projects do not go ahead. “Support for the proposal was mixed, with no majority in favour or against (but slightly more against).”

Contracts will return to the Renewables Obligation length of 20 years, and the maximum strike price is back up to £113/MWh (in 2024 prices).

The impact assessment recognises that the amendments “may increase the subsidy” but for this “to be offset by significant non-monetised and non-power sector impacts.” With the political consensus on renewable energy giving way to the culture wars, that’s a difficult message to communicate to consumers facing rising taxes.

The renewable investment trilemma is the need “to appropriately balance the risks between Value for Money (VfM), bill affordability and investor confidence”. That circle is unsquareable for 8.4GW of offshore wind.

Consumer support for low carbon electricity remains high, but not at any price. In a cost of living crisis and facing rising taxes, public acceptance of net zero is declining and under threat.

They see offshore wind benefit when costs go down, and projects cancelled or rebid when they go up.

They see offshore wind paid the strike price when markets fall, and projects profiting from delay when market prices are high.

The upcoming auction in the Netherlands has been delayed and scaled back, while the contract won by Zeevonck for the IJmuiden Ver Beta site has been amended, to outrage from rival bidders. Following the lack of bids for offshore wind in recent Danish and German auctions, developers in those countries are calling for CfDs.

CFDs remain “the government’s flagship policy for incentivising new low-carbon electricity generating projects in Great Britain” but when developers can terminate projects, rebid at a higher price, and renegotiate terms, it increases the risk of a consumer backlash.

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It feels blasphemous to say this, but maybe offshore wind is just too expensive right now to contribute significantly to the 2030 target.

And a different approach might be needed for offshore wind to maximise its contribution to Net Zero by 2050 with enthusiastic consumer support.

The one thing that everyone agrees on is that a new solution is needed, but any market reform will involve trade-offs and compromises between:

• generation and demand

• investment and operations

• price granularity and market liquidity

• the past and the future

The expected decisions on zonal pricing in Great Britain and Germany are not the end of the discussion on market design.

They are not even the beginning of the end. But they are, perhaps, the end of the beginning.

What is zonal pricing?

An electricity market divided into geographic zones based on bottlenecks in the transmission network is described as having zonal pricing. When congestion prevents electricity flowing freely from one zone to another, their prices will diverge. If this occurs, the price for each zone is determined by the balance of supply and demand within that zone.

• A zone where demand exceeds the capacity to supply locally or import from other zones will see prices rise, incentivising demand reduction, and investment in local generation or expanding network interconnection

• High renewable generation capacity in a zone may exceed the capacity to consume locally and export to other zones, with low prices incentivising higher demand or generation turn down, attracting investment in new demand (e.g. data centres and electrolysis) and expanding network interconnection

Why is it such a hot topic?

In the early days of electrification, it was more efficient to burn coal in power stations near demand. The development of high voltage distribution and transmission lines reduced losses from transporting power. Instead of shipping coal to be burned in cities, power stations could be built near coal mines. Our grids were built to transport power to the people from these large power stations, and heavy industry developed near the sources of power and gas.

Recent investments in generation have been dominated by wind and solar, and focused on locations that maximise their output - more wind in remote, northern regions, more solar in the south. Offshore wind, and rooftop solar on the distribution network, are both in their own way bringing power generation from new areas.

Already recognised in this Clean Energy 2016 Wire infographic, there is a growing mismatch between the capacity of the grid to move electricity from where it is now generated to where it is consumed.

What’s happening to address this?

To prevent transformer overload, grid operators are having to take action to curtail generation in constrained areas. When the market construct ignores these physical constraints they have to compensate these generators. And as these curtailments leave the national market short of power, they have to pay generators downstream of the bottleneck to ramp up.

Redispatch frequently requires the curtailment of renewables in conditions ideal for generation, and ramping up dispatchable fossil fuel generators that were too expensive to clear in the national market.

Over the last 3 years this cost in Germany alone has exceeded €10 billion.

Expanding and reinforcing the network could eliminate all congestion, but is neither economically nor physically feasible. In any case, annual grid investment is expected to rise between 2 and 3 times current expenditure to €100bn per year. Even so, a JRC assessment anticipates redispatch “to increase massively”.

With bottlenecks also between national grids, the EU target to increase interconnector capacity was raised to 15% by 2030. At the start of 2025, although more than half of the EU member states were already above this level, 3 in 10 had yet to meet the previous target of 10%.

Recognising that physical bottlenecks in the grid are not reflected in market prices, debates over introducing and amending zones have been heating up.

Are decisions imminent?

A decision on introducing zonal pricing in the GB market is expected soon. The Review of Electricity Market Arrangements (REMA) ruled out nodal pricing, but ongoing uncertainty over the future pricing regime, and its effect on existing investments and upcoming CFD auction is causing concern to developers and investors. Jonathan Brearley, CEO of Ofgem, has asked for an “honest conversation” about zonal pricing. Yet the debate has remained polarized.

Initiated in 2019, entso-e’s review of Central European and Nordic bidding zones was published shortly before the Iberian blackout, which has somewhat overshadowed its impact. European member states affected by the BZR now have 6 months to come to a unanimous decision. However, with the input data collected in 2019, before both covid and the 2021-22 energy crisis, many of the assumptions on renewable generation and storage capacity are already outdated.

Is anyone happy with the recommendation?

The analysis found that splitting Germany into 5 zones would deliver the greatest economic efficiency. Likely to result in higher prices for southern Germany, the initial response has not been positive.

But the counterpoint, lower prices in northern Germany, where excess wind generation is constrained from reaching the south, would have impacts far beyond the country’s borders.

Unavailability of fossil fuel plants during a period of low renewable generation saw intraday prices spike to Eur900/mwh for the evening of 12 Dec 2024. Importing from its neighbours, the price spike was exported to the southern zones of Sweden and Norway.

Sweden’s energy minister was “furious with the Germans, ” while her Norwegian counterpart was less restrained. within weeks, Norway’s coalition government split due to disagreements on energy policy, with a single national retail price proposed by the Prime Minister.

While the BZR considered a potential reconfiguration of bidding zones in Sweden, unlike Norway moving to a single price for consumers would require European approval.

In contrast, Italy is moving away from a single national wholesale price for consumers, the Prezzo Unico Nazionale (PUN), to match the zonal prices for generation. However, for 2025 if not longer, transitional arrangements will provide “continuity with the calculation of the single national price.”

It seems that everyone wants something different to what they have, but the process of change is slow and difficult.

What will another market reform achieve?

Since the Central Electricity Generation Board was replaced in Great Britain by the electricity pool market in 1990, there have been the New Electricity Trading Arrangements of 2001, their extension to include Scotland in the 2003 British Electricity Trading Transmission Arrangements, and Electricity Market Reform in 2012.

In this time there have been nearly 500 Balancing and Settlement Code modifications and numerous Significant Code Reviews.

Since 2009 the European Union has announced the 20-20-20 Climate and Energy Package, Energy Union Strategy, Fit for 55, Clean Energy Package, European Green Deal, RePowerEU and the latest Electricity Market Design Reform and Action Plan for Affordable Energy.

Policy stability seems to be little more than a myth, and still the one thing everyone seems to agree is the need for reforms that give better signals to generators to adapt their behaviour, to influence decisions on investments that it locates where it delivers most value for the system overall, reducing the costs of managing the system so that we spend less on network expansion.

Better price signals will incentivise consumers to adapt behaviour, encouraging flexibility and intelligent demand. Zonal pricing would put the cost of congestion, which at present is shared across all bills, into wholesale market prices in the zones where it arises.

How does zonal pricing affect wholesale prices?

Congestion between zones means that wholesale prices will vary by location. Zones with high demand will face higher prices, and those with excess renewables lower prices. For all the arguments between models looking at Great Britain, they seem aligned on where and when this will occur - Northern Scotland will have lower wholesale prices, England and Wales higher, particularly the South Coast. Initial savings from redispatch are likely to reappear as an increase in the wholesale price.

Is it fair that market changes will impact investments made over the past decade? You could make the case that some generators should get paid less - after all we've been talking about zonal pricing for 5 years and more. It’s not exactly been a secret that installing more wind and solar will increase curtailment. But we can either accept that there will be winners and losers from the change, or we can mitigate the impact.

Given that investments have been made in response to government targets and incentives, the British government has signalled that existing windfarms with CfDs, and those bidding into the next auction would be “insulated from zonal price risk” if a zonal system is adopted. This could take the form of correcting their reference price to a zonal reference price and also addressing their volume risk. With government auctions seen as driving investments in renewable generation for the foreseeable future, stability is seen as an imperative for the success of future auctions.

The equivalent commercial arrangements, Power Purchase Agreements (PPAs), are unlikely to be protected. Would this put both developers and corporates off PPAs, and slow down the build of new renewable generation outside the government backed auctions?

Would consumption change?

Zonal wholesale prices for consumers is often referred to as a postcode lottery. To some extent, this argument is misguided - regional pricing already exists due to transmission and distribution network charges. And it exists in other sectors, although for rail and air fares, Uber surge pricing and now concert tickets, it is begrudgingly accepted, if not downright unpopular. A radical change for consumers may be even less politically acceptable than for generators.

Low regional prices have been cited as an incentive for large consumers such as data centres and hydrogen electrolyzers to invest in Scotland. This is unlikely to influence residential consumers and small businesses, who won’t move to another part of the country just for lower energy prices. Zonal pricing may also have a limited impact on decisions to buy an EV or install rooftop solar, which are not taken for purely financial reasons.

Consumers do respond to prices, whether time of use network tariffs, dynamic wholesale pricing and tariffs for EVs and heat pumps. But it is unclear how much additional demand flexibility can respond to zonal prices. Renewable curtailment tends to occur when wholesale prices are low anyway. And the price spikes affecting southern zones in Sweden and Norway did not prove popular.

How will this impact networks?

Nothing changes overnight to the physical system we have. We wake up with the same generation, the same wind turbines, same demand, the same congestion and constraints, and the same curtailment when the wind in northern Germany and Great Britain exceeds both local demand and the capacity to transmit to demand in the South.

Although “building out the grid while at the same time developing plans to split the market doesn’t make sense,” zonal pricing would change the evaluation and prioritisation of currently planned network build. And with rising costs already pushing Australia to reconsider “transmission network projects previously identified as critical,” current plans for network build used in the European and GB assessments of zonal pricing are unlikely to match what would actually get built.

Practicalities of Project Development

While zonal pricing has the potential to improve investment and operational signals by better reflecting network constraints, it is by no means the only factor. Securing suitable land, navigating planning regulations, and obtaining timely grid connections can overshadow the nuanced signals from market design.

Higher wholesale prices might not be sufficient to compensate for the intense competition from housing and data centres for land in the densely populated south of England, the planning regime, which has historically presented challenges for wind turbine deployment in England, and the lengthy grid connection queue.

Many countries are grappling with substantial grid connection backlogs, with requests often far exceeding immediate capacity. While connection queue reforms are being implemented to expedite shovel-ready projects, the immediate priority for developers often remains getting projects built and connected swiftly, regardless of future market signals.

With ongoing uncertainty, developers might still build solar where it is sunny and wind where it is windy, and either accept curtailment, or anticipate that future investments in demand, storage, and network upgrades will mitigate it.

Is zonal pricing a marginal question?

The debate around zonal pricing frequently intersects with the broader discussion on marginal pricing, where electricity auctions clear at the cost of the most expensive generator required to meet demand. This mechanism led to significant price spikes when rising gas prices, exacerbated by geopolitical events, impacted even countries with high renewable penetration.

Consequently, there are persistent calls from some quarters to decouple electricity prices from gas, with proposals ranging from nationalizing gas generators to alternative market designs. While such measures might reduce price volatility, a lower overall wholesale price could lead to higher CfD payments, presenting a different set of financial implications.

One concern was that renewable generators were making excess profits when electricity prices followed gas upwards during the crisis, without a corresponding increase in their input costs. But the rush to capitalize on those prices led to a boom in solar generation across Europe.

Now we are seeing the impact of solar generation in negative prices and higher intraday spreads. Are those signals feeding through efficiently into decisions for investment in storage and networks? Sometimes the physical response lags market signals.

Is central planning the answer?

When market outcomes fail to align with anticipated results, governments and regulators often lack patience to wait before announcing interventions and reforms. If governments will not accept the results of market processes, would it be better to drop the pretense entirely?

Generous feed in tariffs have come and gone but net metering still lingers, while regulated consumer prices introduced during the crisis largely remain. Administratively set prices for UVAM in Italy and NEBEF in France have hindered demand side flexibility, while planning restrictions have hampered onshore wind from Britain to Poland.

Even Germany’s decision to shut down nuclear power after the Fukushima disaster came just 6 months after the 2010 decision to extend their lifetimes. Although the ongoing debate around zonal pricing contributes significantly to investor uncertainty about future regulatory frameworks, past decades have not been an environment of policy stability.

Although state planning may have had us building CCS coal plants, new nuclear and hydrogen filling stations, the current preferred approach is being described as “a more strategically planned system.”

That said, it sounds worryingly like Gosplan when Ofgem says “These changes will provide clarity to everyone – investors, network companies, customers – on the assets that need to be built and where they should be located.” A recent update outlines the Strategic Spatial Energy Plan as an Iterative process updated every 3 years that will “identify suitable locations and facilitate access to them in line with strategic energy plans”.

Perhaps strategic central planning would be the best way to align investments in networks and generation. But even when long term frameworks are introduced, such as the Renewable Energy Zones in Australia, incorrect assumptions can upset the best laid plans.

And although “no plan of operations reaches with any certainty beyond the first encounter with the enemy's main force,” in the electricity sector there are multiple forces including investors, developers, and consumers that will have unexpected impacts. Or even a bat colony.

The models don't matter (as much)

And so we return to the models, which can help us think about the future, but the assumptions required cannot give the certainty needed to predict it. Not the “world’s largest machine” as so often described, electricity networks are complex systems. Changing the market structure will change the assumptions modelled that justified the decision to make the change.

Afry highlights the “difficulty involved in a credible assessment of the interactions between locational pricing, CfD strike prices, grid charges and consumer welfare while also holding generation and network build fixed.”

After the introduction of locational pricing, generation and network investments will differ from the assumptions used in the model. As may the assumptions on whether existing investments in generation will be insulated, the political acceptability of a postcode lottery of prices for consumers, and how investor and consumer behaviour will be impacted. We may be heading towards the “fourth, fifth and higher degrees” of the Keynesian beauty contest.

Apart from the immediate impact on wholesale prices, perhaps the one area where the models align is that the cost of capital is the most sensitive factor influencing investment decisions.

Prolonged discussions around market reform increase investor uncertainty. But zonal pricing requires ongoing review, constantly striving for the optimal balance between granularity and liquidity, between wider physical interconnections and local pricing, between the network as is, and as it will be.

The models are just one element supporting the decisions to be taken over the next few months, and whether the number is positive or negative, the benefits of the changes quantified by each model is marginal. Other factors will determine the outcomes.

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This is the end

We are looking for a market that gives signals for investment and operation, for generation and consumption, and to reflect the changing physical realities of the electricity system.

Regardless of the decisions taken this year, within the decade I suspect we will again be facing similar questions on electricity market design.

By then we will have to look deeper into the system, at distribution level congestion, at the overlap between wholesale and retail markets, and the changing needs and provision of flexibility.

Most of the current discussions on zonal pricing focus on the transmission system. Is this a step in the right direction, or a distraction that defers the decision on more fundamental market reform?

The expected decisions on zonal pricing in Great Britain and Germany are not the end of the discussion on market design.

They are not even the beginning of the end. But they are, perhaps, the end of the beginning.

We can’t eliminate all risk but the human impact is so high, and citizens of Europe so unprepared, that we need to learn the right lessons.

In just the last 6 months there have been major blackouts in over half a dozen countries, with diverse causes, from the rupture of a fuel pipeline to drone attacks on an hydroelectric dam, to infrastructure failures at transformers, high voltage lines and generators tripping offline, and natural causes triggered by storm damage and lightning strikes. Even squirrels have been blamed.

It may take another 6 months until the investigations have concluded to know what happened in Iberia. There will be many, from the Spanish and Portuguese governments, Red Electrica the Spanish TSO, the European Commission, entso-e, acer and others.

Until then, conspiracy theories will abound - even before power was restored the incident was being blamed on a cyber attack, too much renewable generation or a rare atmospheric phenomenon.

But what was rare when I was a child is now commonplace, and what was common is now rare.

Even those with good intentions are mostly proposing a simple solution - whether fossil fuels or nuclear from the incumbent lobby group, to batteries, synchronous condensers and flexibility markets from the energy transition evangelists.

Would any of these have prevented the incident? Maybe, but it is unlikely that it would have done so alone.

It is increasingly important for power systems engineers, energy regulators and market participants to understand each other.

This understanding comes from both sides - not jumping to conclusions, but also explaining better.

I am not an engineer, and much of the investigations will rely on arcane technical language. But over more than two decades as an observer, analyst and trader in European energy markets, it has been my affliction to try to expand my understanding of how markets, regulations and technologies interact as a system.

I will try to use language that is more understandable, and link to more technical documents, so please excuse any simplifications, request clarifications if anything is unclear, and help me to better understand any errors I make.

This is my attempt to piece together what we know about what happened and the order of events - not just between the ““event” akin to loss of power generation” and the “massive” loss of power on the system 5 seconds later, but also before and after.

I’m going to focus on four distinct phases, in each of which the impact could have been prevented or mitigated, and in each there are still multiple unknowns and will be multiple remedial actions.

These are the oscillations, the disconnections, the collapse and the recovery.

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Oscillations

Did sub-synchronous oscillations trigger the blackout*?

This has been much of the focus, and likely much misunderstanding, of the past week. Firstly, it is important to better understand what sub-synchronous oscillations are.

“Neither a new phenomenon nor an exclusive challenge to renewable-based systems”, NESO described them in a report last year:

SSOs are certainly not new. A 1981 report from the Swedish State Power Board described the term as an umbrella for three phenomena resulting from electrical oscillations at frequencies between 0-50 Hz affecting generators: Induction Generator Effect, Torsional Interaction, and Transient Shaft Stresses.

While this classification pre-dates renewables, in 2023 Cigre proposed expanding it to include issues related to power electronic devices:

These descriptions are not overly accessible if you’re not a power systems engineer.

It has taken me a while to twig that the reference to 50 Hz, the frequency of the European electricity system, is a red herring. This wasn’t helped by the many images shared showing grid frequency oscillations around 10 and 20 minutes prior to the blackout.

Back to the NESO report, which investigations oscillations on multiple occasions between Summer 2023 and May 2024, and had also been observed in 2021.

These were contained before any loss of load, and the investigation found “no evidence to suggest that the cause of these events is directly linked to system inertia, short circuit levels or any specific type of generation”.

As the image above shows, SSOs are power system oscillations, in voltage and phase angle, that occur at low frequencies.

The voltage oscillations in Scotland were found to have been caused by mistuned control systems of a particular asset, which required mitigation issues before a phased return. Measures also involved retuning voltage controllers of synchronous machines - not just inverter based units. Feedback loops in the control algorithm can amplify the oscillations. Issues with incorrect system controls were also found to be the cause of incidents in Australia.

NESO also found that the “typical low coverage of phasor-measurement units (PMUs) is not sufficient anymore” recommending “increasing numbers of PMUs to be installed at more substations and circuits”, with “high-frequency measurement to monitor the system damping in real time”.

Stability studies have traditionally used Root-Mean Square (RMS) models of the transmission network, which were sufficiently accurate when it was dominated by synchronous machines. More accurate and granular Electromagnetic Transient (EMT) models are now required, which are highly complicated and computationally expensive.

Would more inertia, whether from thermal generation, synchronous condensers or grid forming inverters have prevented the oscillations?

A paper presented at the 22nd IET International Conference on AC and DC Power Transmission highlighted that “synchronous condensers (SCs) inherently have the ability to mitigate SSO, but this ability is limited. To achieve satisfactory SSO mitigation performance, however, an adequate control strategy should be implemented into SCs”

Going further, a post by Nemo Bourbaki suggested that “More inertia would lead to less damping and lower frequency which is more difficult for control systems to manage”.

Are oscillations higher magnitude at the end of the grid?

This is their suspicion, which might align with NESO’s observations in northern Scotland. REE reports that the first loss of generation occurred in South West Spain ***

Other grid operators are improving their ability to observe and model the phenomenon, and are ensuring connected units have appropriate control settings. More inertia is necessarily the solution, and may even exacerbate the issue. It is not caused by renewables, but the changing structure of the grid requires an evolution of approaches to manage it.

So sub-synchronous oscillations in voltage and phase angle, amplified by mis-tuned controls, and at the end of the grid may have been the trigger. But if they have been observed without causing blackouts, why would this have been the case here?

Disconnection

What caused the generation and interconnector to trip?

A lot of the initial speculation is that the decline in frequency caused generation to trip. This is also likely to be an incorrect assumption, at least for the first events.

What generation units went offline, and where?

The NESO report identified that a few plants suffered an adverse reaction to the oscillations, and unexpectedly disconnected. “A few of these events were due to control interactions, while others were due to mistuning of units’ controllers or issues with units’ phase locked loop function.”

Were control and protection settings inappropriately or incorrectly set resulting in units disconnecting unexpectedly?

Was this connected to higher magnitude oscillations at the end of the grid?

With the initial loss of generation in South West Spain - a long way from the connection to France - why did the interconnector disconnect?

The interconnector is an HVDC underground cable stretching 65km, including an 8.5km tunnel through the Pyrenees. It was the first electrical link of its kind to use VSC (Voltage Source Converter) technology. Was this a factor in the disconnection of the interconnector?

As you can tell from the map, Spain is much less interconnected than other European countries.

Would more interconnectors have provided redundancy, or would both have tripped?

A second interconnector, this time a 300km subsea project across the Bay of Biscay is in progress. According to the developer of the France-Spain interconnectors, “Electricity systems are more stable the more networked and interconnected they are.”

What happened to frequency levels in Spain and Europe when the interconnector disconnected?

With Spain exporting to France, the loss of the interconnector should have resulted in a rise in frequency in Spain, and a fall in Europe. This does not appear to have been the case from data currently available.

Collapse

Why did this lead to a complete collapse within seconds?

This is a question also posed by UK Network Services - “So what happened? The fact is we don’t know. Frequency is really the only thing that ties all the generators together, but from the data we have it can’t have triggered what happened that fast.”

It is difficult to reconcile the sequence of events at sub-second granularity with the available data. We may have to wait for the investigations for that to be pieced together from telemetry that was frozen at the point of blackout, and may not have .

Was the collapse in PV generation triggered by Limited Frequency Sensitive Mode - Overfrequency?

Although the image above is not clear and the chart cuts out at 50.2Hz, after a drop to 49Hz, frequency rises to the level at which PV inverters are often programmed to reduce their active power output.

Given that telemetry was frozen when power was lost, any charts showing frequency and generation from Spain during or after the incident should be treated with scepticism for now. We cannot draw conclusions, but we can ask questions.

Did this cause simultaneous reduction of output from the PV generation that at the time was meeting 60% of demand?

Regardless of the reason that generation started to trip, we know from REE’s statement that this led to a “total loss of power”. As pointed out by Lion Hirth, the chart of demand available from REE that shows demand recovering from around 12 GW is inconsistent with this.

Similarly, available information shows frequency dropping only to 49.85 Hz - far above the level that should lead to protection settings taking generation offline.

How fast and how far did frequency actually drop?

Nonetheless, protection settings for solar generation should be a particular focus for the investigations.

The final report on the power system separation of Iberia from Continental Europe on 24 July 2021 was only published in March of the following year. The key finding was that “Avoiding tripping of generation connected to distribution systems is essential to maintaining system security” and recommended that parties “ensure that the mandatory system security requirements are implemented and monitored for their compliance” as “the limits of stable system operation can be reached, even if all security evaluations are executed correctly and timely”.

Was this recommendation implemented, especially for distributed generation?

Earlier in the month, REE announced that Spain had achieved its first weekday of 100% net renewable generation.

Was Spain aiming too high, too soon, for 100% renewables?

The DS3 programme (Delivering a Secure, Sustainable Power System) was initiated in Ireland in 2011, developing a range of ancillary services to raise the operational limit for renewables to 75% of demand.

Should Spain be limiting renewable generation?

At this level of non-synchronous generation, system inertia is low. This means that frequency will drop more quickly in response to a loss of generation. New response services were introduced in order to accommodate an increasing level of renewables.

What were inertia levels in Spain on Monday?

Were these within safe boundaries for system stability?

Other countries are replacing the inertia lost when thermal plant is not generating with flywheels and synchronous condensors.

Should Spain be procuring inertia to maintain a minimum level?

Ancillary services markets in Spain are lagging other countries in implementing the requirements of the 2019 Clean Energy Package.

In particular, Spain does not have market based procurement of Frequency Containment Reserve. It is a mandatory, non-remunerated product. It is also unclear whether renewables can be BSPs for FCR.

Is this requirement applied to renewables?

Was sufficient FCR available to REE for the level of inertia?

Does REE apply dynamic dimensioning of AS, securing more when inertia is low?

Should Spain move to market-based procurement of FCR?

There are answers to these questions that may be valid for normal conditions, when Spain is connected to the European grid. But they change when it disconnects. Iberia has now disconnected twice in the past 4 years.

Was Spain relying too much on limited European interconnection?

FCR requires full activation within 30 seconds. When connected to the European grid, this may be sufficient. But was clearly inadequate when it disconnected and had to operate in island mode.

Should REE reserve capacity capable of Fast Frequency response?

From pilot projects, such as Enhanced Frequency Response in GB, or the Fast Reserve Pilot in Italy, to the enduring products - the Dynamic suite in GB and Fast Frequency Response on the Nordics, services capable of sub-second response are appearing on grids.

While this may only be required when Iberia disconnects from Europe, should Spain maintain contingency reserves for a system split?

Markets for FCR and FFR have supported the installation of batteries to provide those services. Wholesale price spreads in many markets reward merchant trading. Capacity markets and subsidies have also been introduced in other countries.

Incentives to pair storage with solar in Spain are restrictive. Volatility in wholesale markets have been dampened by limits on the price of gas. The introduction of a capacity market has been discussed for 4 years.

The deployment of batteries in Spain is underdeveloped compared to most European countries.

It is not even a question of whether, but how should Spain support the development of batteries on its grid?

But even if all of this had been in place, and still proved insufficient, grids have ‘Low Frequency Demand Disconnection’ schemes that disconnect demand to protect the grid. “Spain never even got near the low Frequency level where this would start to happen.”

Why didn’t low frequency demand disconnection kick in as it did in the UK in 2019?

The tools available to prevent total collapse were clearly inadequate. Iberia acted like central European countries with multiple interconnectors, yet when disconnected was more like the non-synchronous islands.

Recovery

Bringing the grids back online appears to be the one phase where the TSOs of Spain and Portugal should be applauded.

Spain’s Black start required hydropower, CCGTs and the interconnectors with Morocco and France to gradually bring the grid back, 61% by midnight and 99% by 7am on Tuesday.

In Portugal the Castelo do Bode hydropower dam and Tapada do Outeiro natural gas power station helped restore power to 80% of the population by midnight.

Reservoirs were full and hydropower was available, but a black start of this magnitude is still a major achievement.

Can these assets be relied on to be available in future?

Should Spain develop distributed black start?

While it was an achievement to bring power back as quickly as they did, it was not the right time or the right tone to say that Spain has the best electricity system in Europe.

Much of what we know should not have happened. And there is still much we do not.

It has never been possible to eliminate the risk of blackouts, but Spain could have learned from solutions implemented in other countries.

The multiple causes that resulted in system collapse will require multiple solutions. Some may involve trade-offs. All will involve costs. And they will span technology, regulations and markets.

This makes it even more important that we learn the right lessons, and do not jump to conclusions that lead us to implement simple solutions.

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* Systems engineers talk about N-1 (N minus 1, confusingly sometimes N+1 is used to mean the same) redundancy. This means a system continues to operate normally despite the failure of a component. This requires redundancy in the system - excess generation capacity or duplicate feeders. Red Electrica reported oscillations in N-0 conditions - before any fault was detected.

** Much as I try, my understanding of reactive power and phase angles remains somewhat simplistic. And I just can’t quite get my head around short circuit level.

*** I’d be keen to hear from Reactive Technologies on this topic

Over the past six months, there have been plenty of examples of blackouts in countries where the power sector is dominated by oil and gas, without provoking the same level of attention.

And while the immediate cause of the blackout is different in each case, we should learn from the similarities.

Let's start with Cuba, which suffered a total blackout in October 2024, closing schools and industry, ultimately leaving 10 million people without power. Following weeks of rolling blackouts, the grid collapsed again the following Saturday after attempts to restart 5 oil-fired power stations that provide over 80% of the country's electricity, and again in November after a hurricane tore through the island.

On to Juba, the capital of South Sudan which has been struggling with blackouts since the pipeline transporting most of the country's oil exports ruptured. The IMF mission earlier last year pinpointed the drop in oil revenue as the cause behind a 6% fall in GDP and the government's inability to pay salaries.

Next, to Nigeria, where the grid collapse in early November, caused by a transformer explosion, was the third blackout in a week. The petrostate's power sector is dominated by natural gas, yet faces more downtime than countries investing in renewables.

Long notorious for rotating blackouts, in February 2025 power cuts in South Africa jumped to the highest level for a year despite significant repairs to the coal-fired fleet.

98% of the population of Chile were left without power in February due to a fault on a transmission line.

The transmission company that triggered this claims a safety mechanism misfired, taking down the main and backup lines. After this 200km section shut down it triggered cascading failures. I heard on the radio that one substation exploded, but didn't find news about it.

Blackouts also returned to Cuba in 2025, with the failure of a substation near Havana in March. After a brief respite in January, that remains the only month without blackouts in the last six.

The Pacific island of Samoa has been facing rolling blackouts for much of March, with kerosene lamps used at night and a 30 day state of emergency being declared. The surge in demand for power over the last two years has placed increasing strain on a grid facing damage from storms and multiple failures at key generators.

In the ongoing civil war in northern Sudan, the hydro-electric power station at the Merowe dam has been targeted with drones, damaging the transformer and resulting in a complete outage.

And so back to Spain, where government intervention in the electricity market has been both extensive and limited.

In order to match demand to the profile of solar generation the default PVPC tariff was originally set to follow the hourly wholesale price. However with volatility increasing following both COVID and Russia's invasion of Ukraine, the price signals given to influence demand have been softened. The government also capped the price of gas used for electricity generation. This meant that while other countries faced higher and more volatile prices that incentivized installation of solar and storage, gas generation in Spain remained high.

The role of independent aggregators remains limited, restricting the growth of flexibility both from residential assets and commercial and industrial businesses.

Frequency containment reserves (FCR) remain a mandatory, non-remunerated product in Spain. This has been one of the main drivers for grid scale storage across Europe. European guidelines for system operation (SO GL) require frequency containment reserves to be dimensioned to cover the reference incident:

The reference incident is defined as the maximum expected instantaneous power deviation between generation and demand in the synchronous area for which the dynamic behaviour of the system is designed. This expected instantaneous power deviation includes the losses of the largest power generation modules or loads, loss of a line sector or a bus bar, or loss of a HVDC interconnector. The SO GL (Article 153 (2b.i)) sets the reference incident for CE to 3000 MW in both directions.

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I have 3 concerns with this:

1. cascading failures

2. the relatively slow response time of FCR

3. the likelihood of a system split affecting Spain

Cascading failures

The concept of a single reference incident defining the size of reserves required seems outdated in an increasingly decentralised system. In addition to the examples above, the partial blackout in Great Britain in 2018 was the result of multiple failures resulting from a lightning strike on a transmission cable. First Little Barford CCGT tripping, then Hornsea One offshore wind farm, followed by embedded generation - a total loss of generation greater than the maximum single infeed loss. This led to the acceleration of the loss of mains protection programme to:

help to allow a ride through during a network fault and reduce the amount of generators cascade tripping as a result making the problem worse.

Furthermore , while historic needs for flexibility have been to cover the risk of a generator trip , there is increasing need for downward flexibility driven by the potential sudden loss of large demand from data centres and interconnectors.

Faster frequency response

Other countries around the perimeter of the synchronous European grid have gone even further than FCR, creating markets for fast frequency response in the Nordics and Ireland and the dynamic suite in Great Britain. Even Italy introduced a fast reserve pilot. With Spain’s limited interconnection, it is at higher risk of disconnecting from the central European grid becoming more akin to the smaller separate grids with a need for FFR.

System split

The separation of the continental Europe synchronous area is not an unprecedented event. In January 2021 an area in the southeast region was separated from the rest of continental Europe, while in June 2024 a major incident caused “a large part of the transmission systems of Albania, Montenegro, Bosnia and Herzegovina as well as Croatia” to suffer a total blackout.

The Iberian peninsula had previously separated from continental Europe in July 2021. The key finding following that incident was that avoiding generation tripping in response was essential to maintaining system security.

The failure to implement recommendations following previous incidents exacerbated the impacts of winter storm Uri in Texas. And the need to improve fault ride-through for embedded generation was already known from the last time the Iberian grid separated.

Interconnector failures, particularly between UK and France, and between the Nordics and Baltics, are are an increasingly frequent risk and have opposing impacts on either side of the split.

Red Electrica Espana participated in a 2016 report for Entso-E which found that:

As long as the system remains interconnected lower system inertia is not considered to be critical for the normative 3000 MW incident.

As we saw on Monday:

• When the system disconnects lower system inertia is critical

• The reference incident is not reflective of cascading failures

• FCR is inadequate to deal with this situation

The centralised electricity system was described as the world’s largest machine. The distributed electricity system is more like a complex system. Feedback loops and tipping points mean that an incident may cause cascading failures, or with an imperceptible change in the starting conditions, that same incident might not.

The cause of Monday’s blackouts may well be the “rare atmospheric phenomenon” as first reported, or it could be something else. This is of little importance. Regardless of the cause, low inertia, a system split, and cascading failures are all likely to occur again. While we can’t predict what will cause the next blackout, we should address how it proliferates.

Once the investigations have reported, maybe the government will be true to its word to take 'all necessary measures' to prevent another blackout. History suggests they may need reminding.

I just never seem to settle on one, or have it to hand when I know I’ll forget something if I don’t jot it down somewhere. And there’s a lot of duplication as I develop thoughts just a little further, or find the perfect example to illustrate the point. Or I just forget.

And so they build up, gathering digital dust. That’s partly why I started this Substack - to collect and organise my notes into occasional pieces that resemble something like a structure.

And then along come LLMs. I’ve tried them too, from ChatGPT to Claude to Gemini to Perplexity. And while I haven’t found the perfect match, I have found a combination that has gathered my notes on electricity markets1 , organised them by theme, and turned them into a podcast2.

Bringing together dozens, if not hundreds, of notes into a 20 minute podcast, I think this is a fair summary of the issues in electricity markets at the moment:

• Energy markets operate across different timescales: long-term development, short-term scheduling, real-time operations, and very short-term balancing.

• Balancing the grid involves constant adjustments to match supply and demand, with prices influenced by generation availability (especially renewables), weather, fuel costs, network congestion, interconnector flows, and market expectations.

• Imbalance prices are determined by the cost of actions taken to correct deviations between predicted and actual generation or usage.

• Marginal pricing, where the most expensive generation sets the market price, is widely used but has drawbacks, as low-cost generators can benefit from the high prices set by expensive units.

• Flexibility, the ability to adjust generation or demand quickly, is becoming crucial, with sources including flexible supply, fast-ramping plants, demand response, storage, and interconnection.

• Storage is a key enabler for flexibility, and its ownership and how it's valued in the market are important considerations.

• Engaging consumers through demand-side response is important, using price signals and tariffs to encourage flexible consumption, but risks to consumers must be managed.

• Renewables are a key driver of electricity market reform, due to their intermittency and the need for greater system flexibility.

• Market design choices, such as energy-only vs. capacity markets, and temporal (e.g., five-minute settlement) and geographic granularity, involve significant trade-offs.

• Integrating renewables leads to challenges like curtailment and negative pricing, requiring incentives for using or storing excess clean power.

• Zonal pricing, dividing the network into zones with different prices, is debated; proponents say it gives better signals for investment, but opponents worry about complexity, volatility, and fairness.

• Market liquidity (ease of trading) and granularity (precision in reflecting local conditions) present a trade-off; wider markets are more liquid, while narrower markets offer more granularity.

• Market failures in energy can include externalities, public goods issues, natural monopolies, information failures, and coordination problems, requiring government intervention.

• Network issues, such as congestion and grid charges, are critical, especially with more distributed energy resources.

• Emerging trends include virtual power plants (VPPs) and peer-to-peer (P2P) energy trading, along with grid-enhancing technologies.

• International examples show diverse approaches to market reform, with each country facing unique challenges3.

Have a listen to the discussion - it’s only 20 minutes. Is anything major missing?

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The cases clarified the duties owed by brokers to consumers and the circumstances under which the party paying the commission to the broker can be held liable for undisclosed commissions.

• Brokers have a fiduciary duty to consumers

• Partial disclosure is not fully informed consent

• Even sophisticated consumers cannot consent without full knowledge

• The party paying the commission is unlikely to be held liable for the lack of disclosure by the broker unless they behaved dishonestly

• Upfront payment of commissions may incentivise the broker to act contrary to the best interests of the consumer

Expert Tooling significantly relied on Firstrand's review and application of the law concerning broker commissions, fiduciary duties, and accessory liability, and was expedited to be heard, and if possible, for judgment to be given, before the Supreme Court hearing in Firstrand.

The lenders are appealing the judgement on the duties owed to customers relied on in the Expert Tooling case. The hearing starts on Tuesday - April Fool's Day.

The Johnson v Firstrand Bank judgment, handed down on 25 October 2024, addressed the scenario of car finance arranged through dealerships, where the dealer acts as a credit broker and receives a commission from the finance company.

The court found that dealers acting as credit brokers owe a disinterested duty and a fiduciary duty to their customers to find suitable and competitive finance deals.

Importantly, the judgment distinguished between secret commissions (no disclosure) and partial disclosure. For consumers to give informed consent to the commission, the disclosure must be sufficient to bring home the potential conflict of interest.

The judgment also considered the potential liability of the lender as an accessory to the broker's breach of duty, noting that in partial disclosure cases, this typically requires a finding of dishonesty on the part of the lender.

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The Expert Tooling v Engie Power judgment, handed down even more recently on 21 March 2025, tackled the issue of commissions paid to energy brokers by suppliers.

This case focused on whether the disclosure made by the energy broker, Utilitywise (UW), to their client, Expert Tooling, was sufficient to constitute informed consent to the commission received from the energy supplier, Engie.

The court found that although Tooling was aware that UW would receive a commission, they were not given sufficient details about the amount or how it was added to the unit price, and therefore informed consent was not obtained.

The judgment reinforced the principle that for informed consent, the principal needs full knowledge of all the material circumstances and the nature and extent of the agent's interest.

The broker has a duty to inform the customer, even though they were considered sophisticated buyers yet did not enquire further when informed about the commission.

Like Johnson, Expert Tooling considered the potential accessory liability of the payer of the commission (Engie), again emphasising the requirement for dishonesty. The supplier would need to have been aware that the broker was not obtaining informed consent or deliberately turn a blind eye to this fact.

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Ofgem has regularly consulted on Third Party Intermediaries in the energy sector, with the judgement referring to a 2015 factsheet for small businesses.

In their example, a commission of 1p/kWh was added to a 10p/kWh cost - a 10% uplift.

2015 OFGEM Factsheet Third Party Intermediaries: what your small business needs to know

Expert Tooling paid a commission of 5.6p/kWh.

Expert Tooling significantly relied on Firstrand's review and application of the law concerning broker commissions, fiduciary duties, and accessory liability, and was expedited to be heard, and if possible, for judgment to be given, before the Supreme Court hearing in Firstrand.

The lenders are appealing the judgement on the duties owed to customers relied on in the Expert Tooling case. The hearing starts on Tuesday - April Fool's Day.

With Sheffield steel exported all over the world, Lee & Wigfull opened a London office on Holborn Viaduct. Linking Holborn to Newgate Street, the road is named for the structure bridging over Farringdon Street, which itself was built over the route of the Fleet River. The viaduct meant that vehicles no longer had to descend to the level of the tributary of the Thames, and back up the other side.

Next door to Lee & Wigfull’s office, at number 57 Holborn Viaduct, was the Edison Electric Light Station, the world's first coal-fired power station generating electricity for public use. Behind the shopfront facade, a 93 kW generator weighing 27 tonnes powered electric lighting from Holborn Circus to St Martin’s le Grand before closing in 1886 as a technical, but not commercial, success.

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Terrence Cuneo was commissioned in 1947 by Ford to make a series of six paintings depicting the company's Dagenham plant. The picture above, “Ford Thames Foundry” shows the jetty for receiving deliveries to keep the on-site power station and steel foundry running.

Constructed to the east of London in 1929 to replace the Trafford Park plant in Manchester, the site was the first European car plant to be self-sufficient. Burning coal and London’s waste to generate tens of megawatts of electricity, it also supplied houses connected to the local grid.

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But larger power stations were already being constructed by local supply companies, including the iconic Battersea Power Station. Although construction started the same year as Ford’s Dagenham plant, Battersea wouldn’t be operational until a couple of years after cars started rolling off the production line.

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From here on it’s a well-known story - the 1930s saw the development of the national grid, as well as the construction of power stations at locations familiar to market observers today, including Ironbridge, Little Barford3, Littlebrook, as well as at Trafford Park in Manchester, the location of Ford’s site prior to the move to Dagenham.

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Local power stations contributed to the Great Smog of 1952, when 4,000 people died in London as a direct result of airborne pollutants mainly from the use of coal. The trend towards large central power stations situated away from built up areas was set. The first nuclear power stations appeared shortly after, accelerating this trend.

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This era still deeply influences the written and unwritten rules of today’s electricity market: large power stations located close to where fuel is produced or imported, generating electricity and ramping up and down to follow the patterns of demand. High voltage transmission networks deliver the power to regional distribution grids, which are sized to meet peak demand even though the average network load is often less than 10% of their capacity. And consumers are passive, oblivious to the needs of the system they pay for.

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This construct is breaking down, as we have plenty of network capacity, but not where it is needed to bring renewable generation from where it is plentiful. New substations to connect large offshore wind farms require large substations and new pylons in regions previously unencumbered by energy infrastructure, resulting in protests against the costs and impact of the developments.

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Distribution networks also need reinforcement, both to accommodate the electrification of demand - from EVs and heat pumps at low voltage to huge data centers on high voltage grids - and growing local renewable generation.

And consumers are no longer passive, but more conscious of costs, and capable of responding to incentives. Buildings are once again becoming integral to the energy system, capable of providing not just energy but flexibility to balance the system and manage constraints.

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This week saw the launch of a report I co-authored with Solar Power Europe, with 5 recommendations to harness this capability:

Set price signals that incentivise efficient use of networks and generation

Complement smart meters with submeters, including those within flexible devices

Tailor technology support schemes for flexibility

Harmonise data communication to facilitate switching between providers

Allow building flexibility to access energy and balancing markets

We will need to overturn decades of entrenched thinking that the electricity system ends at the meter, that demand side flexibility is a last resort, and that retailers own the customer.

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The electricity system of today is not how it always was. But it might become how it used to be.

A formula linked the price of gas at a discount to the market price for the product it was aiming to displace. Usually well above the production cost for gas, this premium would also ensure that the fixed costs of building the pipelines would be recouped.

I've been wondering if developers and owners of public EV chargers have been following the same playbook, and whether they are making a fundamental mistake. The data in this article suggest that they are.

I know I'm making a huge generalisation, but there are two broad categories of EV driver: firstly those who mainly charge at home, and only use public chargers for long journeys. This is the equivalent of occasionally filling up at higher priced motorway services. It costs more than at your local supermarket and most people avoid it when they can. Fast charging appears to be priced at a discount to these.

But to get beyond the early adopters who can charge at home, to those who will use public chargers as they fill up with petrol and diesel today, the cost will have to reflect this behaviour. However, the price of public charging appears to have been set not at a discount to the local forecourt, but instead at a premium.

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As the article, based on the AA EV Recharge report, says: this is "Why owning an EV only beats petrol if you can charge at home". Changing this would not only accelerate uptake of EVs, but will also increase the utilisation rate of chargepoints, still languishing below 20%.

To ensure that they would be used, the gas pipelines only had to keep the cost below that of oil. And once consumers had switched their appliances, they had a monopoly over supply. I can understand why public chargepoint operators would see the equivalence.

Once someone has an EV, but can’t charge at home, they have to rely on public chargepoints. The vast majority of EV drivers say they wouldn't go back to an ICE vehicle. But range anxiety, difficulties charging and the high cost of public charging feature high in the lists of reasons preventing people from switching.

Maybe CPOs should be taking advice from Gordon Ramsey's Kitchen Nightmares instead. His recurring recommendation to cope with high fixed costs, volatile input costs and low occupancy was not high prices which would put off even existing customers. Instead, the solution was simplifying the proposition and reducing prices to bring in more customers. In turn, by word of mouth, these customers would help other potential customers overcome their reluctance and encourage even higher occupancy.

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The more that people feel comfortable relying on public chargepoints, the more they will refute the fears holding others back. This should become a virtuous circle for CPOs. For as every restaurateur has found, it's all about getting bums on seats.

At least they call it a deep dive, but it’s starting to sound a little repetitive and superficial to me. For some reason, their first attempt was a much longer discussion, at 40 minutes. While it didn’t give me the depth I was looking for, it did highlight 3 or 4 aspects within the documents that are worth further investigation.

However, the lack of continuity was starting to bother me, so I re-recorded the episode adding the first 2 podcasts as reference material. France and Sweden get a mention, but without really analysing the differences between their approaches.

And although the prompt asked for the hosts to be specific about the opportunities for demand side flexibility, this isn’t mentioned when centralised and decentralised capacity markets are discussed. France could have used as an example to contrast with Spain, while the discussion doesn’t get any more specific than decentralised capacity markets “rely more on market forces and price signals to encourage people to invest in capacity”.

The hosts do give opinions, although I have yet to meet anyone else who says that “Spain's definitely a leader when it comes to DSF”. This differs from most of their opinion which come across as generic. Given that the podcast should be based only on the source material, I am starting to observe discussions that appear to have come from additional external inputs, such as the EU’s guidelines for cybersecurity and interoperability. Yet lacking wider context, in each podcast every country’s proposals are described as ground-breaking.

This podcast feels less useful than the first two, repetitive of their content, and somewhat opinionated. It’s still a beta product, and does have the benefit of narrowing my focus onto specific aspects that need further investigation, but doesn’t (yet) beat reading the documents themselves.

And with the consultation ending today, there will be a few more documents to throw into the mix before too long.

Because if you were a developing country, if you're a global south country, which would you take? Would you take the LNG and become addicted to it forever, or the clean technologies, install them and have an asset forever? Maybe that's the way they think about it, or maybe you just take the cheap LNG, because that's the easiest thing to fit into the existing infrastructure that you've got today.

Michael Liebreich, Cleaning Up

This isn’t a hypothetical question, but one that many countries are grappling with. You might even cite Pakistan as an example where it has actually been tested in the real world. And their answer isn’t as obvious as it might first appear.

Pakistan’s solar boom was one of the cleantech stories of 2024, with an estimated 15GW of solar panels imported last year alone. For a country where electricity demand peaks around 30GW in mid-summer, that’s a revolution, not a transition.

It seems that even those who should know better were taken by surprise. An official from the Pakistan Water & Power Development Authority observed that “If Pakistan continue to receive affordable Chinese solar systems, installed solar capacity is expected to grow from 1.41 gigawatts in 2024 to 9.53 gigawatts by 2029, at a compound annual growth rate (CAGR) of 46.55%”.

9.53 GW had probably been surpassed by the end of summer.

But Pakistan hadn’t chosen solar, having entered into long term contracts for LNG from Qatar in 2015 and with ENI and Gunvor Group in 2017, tied to the price of oil. Investments in regasification terminals and gas-fired power stations aimed to provide security of supply as electricity demand grew and the country started to move away from oil for power generation.

Although from 2021 the price of oil and gas rose as demand recovered from the COVID lows and as tensions increased prior to Russia’s invasion of Ukraine, spikes were much more extreme in gas prices following the start of the war. And with gas flows to Europe through Nordstream halted when the pipeline was sabotaged, Europe turned to LNG. And much of that LNG had already been committed elsewhere.

Already in 2021, ENOC defaulted on its commitment to supply 2 cargoes in February, forcing Pakistan LNG to tender for cargoes on the spot market. A year later, the company filed for arbitration when Gunvor cancelled 4 shipments for summer 2022, having failed to deliver 3 the previous winter. ENI also defaulted on 4 cargoes over the same period, and even the spot market tenders frequently drew no bids.

Yes, Europe “successfully secured gas supply and diversified gas imports away from Russia, with LNG playing a key role in this shift” but will this be a phyrric victory?

Pakistan had chosen LNG, and when those cargoes were diverted to Europe, the instinct was to revert to coal. But with cheap Chinese solar panels flooding the country, the population turned to solar.

The country now finds itself with a surplus of LNG cargoes, and while there are other, less positive causes, ending up with a solar-dominated power system may provide new opportunities to electrify its industry.

Europe attracted LNG to replace Russian gas at huge financial cost. And remains addicted to gas.

The video of the presentation is insightful, entertaining, and somewhat frightening.

The breach left 800,000 EV owners' details exposed, linking locations and travel patterns to military and government entities (including politicians), embassies and broadcasters. It shows where and when they go shopping, to school, or to play tennis.

It poses serious questions on the extent of data car manufacturers are receiving and storing, the lack of security, encryption and anonymisation, and what they then do with the data.

Concerns have been growing over data privacy, with Mozilla in 2023 finding concerns across all vehicle manufacturers, with Tesla only the second company to achieve a clean sweep of privacy warnings.

Of course, to comply with legislation, users can opt out, but when the only way to stop tracking is to disable connectivity altogether which “may result in your vehicle suffering from reduced functionality, serious damage, or inoperability.”

Mozilla found that three quarters of manufacturers could sell the data they collect, and it is little surprise that it was in Germany, where data privacy is almost a national obsession, that this breach was uncovered.

The EU Data Act will from September 2025 give car owners more visibility over the information they generate, with manufacturers required to provide owners with simple and free access to their own data.

But as the researchers say in their presentation, “Trust is good, but controls are better.”

The video, licensed to the public under http://creativecommons.org/licenses/by/4.0, can be watched in the original German, or with French and English audio tracks at: https://media.ccc.de/v/38c3-wir-wissen-wo-dein-auto-steht-volksdaten-von-volkswagen#l=eng&t=1

When flexible capacity exceeds market needs, conventional thinking is that prices will converge with the level that can be achieved through arbitrage in the deeper, more liquid wholesale markets.

If this is the case, there is a risk of “missing money” challenging the requirement highlighted by ACER for "twice the current amount of flexibility resources" to be developed to accommodate the growing capacity of renewable generation.

But that's not the whole story, as this excellent report from Anna Jäderström and the team at Svenska kraftnät shows.

The headlines for me are that while new assets are starting to encroach into the territory occupied by existing flexibility providers, "overall demand for ancillary services is expected to grow over the next five years".

Procured volumes have already increased over the last 5 years, but ”ancillary services have always and will always be needed”. Historically procured and dimensioned to address the unexpected loss of the largest generator, the most significant change is the need for downward flexibility to manage both an excess of renewable generation and the sudden loss of an interconnector exporting at full capacity.

The dimensioning of upward reserves will also have to change, as ancillary services developed to cope with the unexpected outage of a thermal power plant in a system with high inertia now have to maintain frequency with much lower system inertia, weather-driven forecast errors in generation and demand, and failures of grid infrastructure having a larger impact.

One factor reducing the national procurement of flexibility is the sharing of capacity across borders. Svenska Kraftnat’s share of the Nordic synchronous area’s FCR requirement is 37%, of which two thirds must be procured from assets in Sweden. The share of the aFRR requirement is roughly 27%, depending on direction.

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Here are the key figures for each of the markets:

FFR - procured for May to September, the summer months when inertia is low, this is a market for sub-second upwards regulation. Procured annually (and moving to Day Ahead auctions in 2027), 100MW of Demand Response and 330MW of batteries are the only assets pre-qualified for the 250MW requirement.

FCR-D Up - this is the traditional upward frequency response dimensioned to address the failure of the largest generator - currently the 1450MW Oskarshamn 3. Svenska Kraftnat’s, share is roughly 550MW, while 3710MW of assets are pre-qualified. Historically provided by hydro assets, 8 new providers in 2024 have contributed to the 590MW of batteries and 420MW of Demand Response capable of providing the service.

FCR-D Down - downwards response is dimensioned to cope with the sudden loss of the Nordlink or North Sea link interconnectors at their full export of 1400MW. The maximum hourly need for Sweden has risen from below 100MW in 2022 to 500MW in 2025. 550MW of batteries and 380MW of wind are increasing competition to provide the service.

FCR-N - system frequency increasingly requires stabilisation during normal conditions, for which Svenska Kraftnat procures 37% of the 600MW Nordic requirement. Of the 1980MW of assets pre-qualified, 1790MW is hydro.

aFRR - procured separately for both up and down capacity, assets have 5 minutes to reach full activation. Pre-qualified capacity is again dominated by hydro, resulting in higher prices during the spring flood when flexibility is constrained. Wind capacity for downwards activation is growing. The 100MW requirement will potentially grow to 300MW upwards and 400MW downwards by 2027.

mFRR - historically activated after automatic ancillary services, in future scheduled activation will address imbalances. Over 13GW of hydro is pre-qualified, with Demand Response growing for up and wind for down. The capacity market started in October 2023, and procurement is expected to exceed 1GW in 2025.

Average utilisation rates for 2024 show that the most pressing need is for aFRR, particularly down. The requirement for ancillary services is no longer defined by the fixed capacity to cope with the sudden trip of the largest generator, but increasingly a game of cat and mouse between the growth of renewables on one hand, and increasing capacity from new flexible assets and regional procurement on the other.

The growing need for downward flexibility, particularly FCR-D to cope with the sudden loss of an exporting interconnector, was brought into focus by the damage to the Estlink 2 cable on Christmas Day 2024. Exporting from Finland to Estonia, capacity was reduced from 1016MW to 358MW with the damage suspected to be caused by an oil tanker “part of Russia’s shadow fleet”.

Ancillary services requirements, both for capacity and their utilisation, are anything but fixed.

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The last post looked at modelling values from ancillary service, capacity and wholesale markets in Belgium, and was accompanied by an AI generated podcast of the technical documents.

To create the podcast for this report, I asked the AI to consider the Svenska Kraftnat report alongside ACER’s recent reports on barriers to demand side flexibility and market monitor as background. Unprompted, the audio highlights Northvolt as a beacon of Sweden’s energy transition - not directly related to ancillary service participation, nor entirely up to date with developments at the company.

There is also a clear US bias with references to “demand response programmes” when this report and the broader European philosophy is for demand response participation in markets for system needs, in competition with generation and storage.

I found this podcast, lacking the continuity and context of human presenters, to be light on specific detail from the report - contrast the transcript to my post, and somewhat repetitive of the first Belgium podcast.

How does it compare? What could be improved? Share your thoughts in the comments.

Assets have different capabilities to respond to market signals, and can maintain their response for different lengths of time. Some can follow a set point, others are either on or off. Availability varies, especially for demand side assets, primarily owned to provide services to the user, not the electricity system.

They can generate electricity, consume it, or like batteries have the capability to do both. As Lorenzo Kristof put it “in the future, every grid connection will have storage-like properties”. Where they are located, on the transmission or distribution network, or behind the meter on consumption sites will have an impact on the markets they can access.

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Markets are becoming more open to flexibility, whether long-term capacity markets, wholesale energy, or ancillary services providing reserves or frequency response. Trading strategies matter, as does willingness to be activated.

Not only has the Belgian TSO Elia developed a flexibility simulator - What’s happening - that includes all these factors and more, they have also provided documentation explaining how they have done so.

That’s amazing, and it’s not even what blew my mind.

Even if you find this stuff fascinating, you might not want to read through all of the technical documents. So have a listen to this AI-generated podcast, just 20 minutes of discussion covering the opportunities across all of the markets. I was astounded.

It’s not perfect, but accurate and insightful enough to challenge many energy podcasts, and makes the documents more accessible.

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What do you think of it? What did they (it?) do well, what could they do better and what did they just get wrong?