Day-Ahead Market in Energy Pricing

Across Europe, electricity prices remain sharply divergent, with wholesale day-ahead markets still reflecting deep regional imbalances. Recent spot data show Bulgaria and Romania among the highest price areas, with rates approaching ~€280 /MWh in some hours - far above most of Western and Northern Europe. In contrast, markets such as Spain and Portugal often see prices closer to ~€60 /MWh, reflecting greater low-cost generation and market conditions. Two structural factors lie behind this disparity: wind generation and grid interconnections. When local wind output is low, as it has been in Southeast Europe today, supply tightens and prices spike. Even when wind generation is abundant in Central and Northern Europe, limited transmission capacity and constrained interconnectors make it difficult for lower-cost power to flow south and east, perpetuating regional price divergence. The implications are political as much as economic. European governments must prioritise rapid cross-border grid investments to better integrate national markets into the EU internal energy market, scale grid-friendly storage such as utility batteries to smooth variable renewables, and remove policy barriers to wind and other clean generation. These measures will not only help reduce wholesale price and price volatility, but also strengthen competitiveness, security of supply and the transition to net zero — the three pillars of the EU’s energy agenda.

The past week has highlighted the clash between the new rhythms of electricity generation and the old rhythms of demand. When trading electricity, the old constructs of baseload and peakload still rule the roost. Those are the products on the front page of the EPEX SPOT website, listing Day Ahead prices by country. Peakload, representing weekdays from 7am to 7pm, used to be the higher priced period. Today, all but 2 markets - NO3 and GB 30 min auction - have cheaper prices during the peak of the day. It's not hard to see why. Nearly all German peakload demand last week was met by solar power. Midday prices dropped below zero. The energy transition has transformed electricity generation. But on the demand side, the changes have yet to catch up. Demand still drops overnight, despite tariffs incentivising EV smart charging. And daytime demand falls again at the weekend. Even if solar generation does not. The eye-wateringly low prices across Europe last weekend are a symptom of the need to transform demand. EVs and batteries are obvious solutions, while AC, not long ago seen as exacerbating peak prices, may be required to minimise excess generation. Markets offer opportunities for flexible demand. Electrification brings capabilities for demand flexibility. Challenges remain, not least from regulations languishing from the last century, and a lack of interoperability between devices. But with prices at minus €500, incentives are there.

The evening hours when day-ahead prices surged during the recent Dunkelflaute events of 5-7 November and 12 December in Northern Europe were characterised by a tight supply situation amid lack of wind power generation, with the day-ahead prices surging to very high levels for a few hours. Much has been said about this already, but how tight the supply situation was really? Together with Hendrik Diers and Martin S. H. we conducted a comprehensive analysis based on publicly available data. The result is clear: As expected, the evening hours between 16:00-20:00 when the price spikes were observed, were also among the hours with the highest residual load to available dispatchable capacity ratio observed so far in 2024 - both in Germany and in neighbouring countries on average. This shows that supply was particularly tight during these hours across the region. For context: Day-ahead electricity prices in Germany and parts of the Nordic countries exceeded EUR 900/MWh in a single hour on the evening of 12 December. This occurred after sunset and electricity generation from wind was very limited, resulting in minimal electricity generation from these variable resources – the so-called “Dunkelflaute”, dark doldrum. By comparison, the highest hourly day-ahead price in Germany in 2022, at the peak of the energy crisis, was around EUR 860/MWh. A precursor to 12 December was 5-7 November, when wind power generation in Germany and neighbouring countries was also very limited and German day-ahead prices surged after sunset, ranging between EUR 400 and EUR 800/MWh between the hours of 17:00 and 18:00 over these three days. During these two events, electricity consumption increased amid colder weather than in previous weeks, but it was not exceptionally high, and similar load levels were observed in other periods in the 2023-2024 period. 

Forecast bidding is no longer the obvious default. You run a wind farm. Every day before noon, you decide how much power to sell in the day-ahead electricity market. You can bid your best production forecast. Or you can deliberately deviate and bet on the spread between day-ahead and balancing prices. For years, that bet was barely worth making. Europe's old two-price balancing schemes penalized imbalances by direction, which limited arbitrage. But the market has changed. With the move to single-price balancing and new balancing price formation, now shaped by both mFRR and aFRR activation markets, balancing prices have become far more volatile. The spread between day-ahead and balancing prices is now wider, less predictable, and potentially profitable. But also risky. In our new manuscript, we propose a data-driven bidding framework that answers three questions: → When to engage in arbitrage. A probabilistic classifier decides whether the predicted spread is confident enough to act on. Otherwise, you bid your forecast. → Which direction. When engaging in arbitrage, the classifier also tells you whether to go long or short. → How much to arbitrage. A linear policy, learned through contextual optimization, maps contextual features to the arbitrage size, while a CVaR constraint keeps tail risk in check. Using real Danish DK1 and German DE/LU data, the strategy improves mean profit over forecast bidding, by around 7% for a hybrid wind-electrolyzer plant in DK1, for instance. The hybrid plant earns more from arbitrage than wind alone, because the electrolyzer absorbs part of the mismatch internally. That creates more room to trade without sending every deviation to the balancing market. But there is a limit. The gains are strongest when recent conditions still resemble the training period. But the environment is non-stationary: when it shifts, past data becomes a misleading guide and the edge shrinks. This does not explain every bad window, but it points to a real weakness of data-driven arbitrage, one you only see after the fact. Joint work with Yannick H. and Farzaneh Pourahmadi. That is where the project goes next. During an upcoming PhD research stay with David Wozabal, Yannick will build distributional robustness into the framework, so the bidding policy can hedge directly against drift. Preprint: https://lnkd.in/dX2J-ZGt DTU Wind and Energy Systems

Day-Ahead prices consistently exceeded Real-Time prices throughout the peak period of stress (from yesterday evening into this morning) in ERCOT during Winter Storm Fern. But why, and what did it mean for batteries across the system? ERCOT forecasted peak demand as high as 86 GW as late as 8 hours before Monday morning's peak. Actual load came in at just 75 GW. Meanwhile, thermal outages stayed around 9 GW for the bulk of the storm, with the only major event being the forced outage of ~1 GW of generation at 8 PM on Sunday evening, which coincided with an emergency notice being issues for the loss of some transmission and generation in the Houston and San Antonio areas. ERCOT expected ~7.5 GW of thermal generation outages in the highest-concern hour according to its January 2026 Monthly Outlook for Resource Adequacy (MORA) report. Renewable production was also roughly in line with ERCOT's expectations for a Winter 2026 Hour Ending 8 event. In its most recent Capacity, Demand, and Reserves Report, ERCOT projected intermittent renewable production just before 8 AM would be ~GW in an event like today's. As a result of the load forecast and generators across the system holding up under tough conditions, Day-Ahead Energy and AS markets priced in scarcity that didn't fully materialize in Real-Time. DAM energy hit $1,800/MWh for Monday morning, while RTM peaked around $1,000/MWh on Sunday evening. Batteries remained nearly idle on Jan 24-25, maintaining a high state of charge, despite elevated prices on the 25th. Discharge peaked at just 1.7 GW on the 25th. Then Monday morning: discharge peaked at around 7 GW, as operators who'd cleared in the Day-Ahead market executed their strategy. Most batteries likely stacked Day-Ahead Ancillary Service awards throughout the weekend (which cleared above $100/MW, hitting $1,000/MW for RRS, ECRS, and Reg Up on Monday), allowing them to collect revenue with limited cycling requirements. The most successful operators likely went even further. On Sunday evening, with RT AS prices below $10/MW, they could have forgone those DA obligations, capturing the DA/RT spread, and discharging into the $750-1,000/MWh RT Energy peak instead. They then could recharge overnight at $250-450/MWh to meet Monday's DA commitments. This kind of strategy requires precise DA market positioning, confidence in overnight price behavior, and willingness to charge at prices that would normally be prohibitive. Winter Storm Fern showcased how forecast uncertainty and a willingness to leverage a battery's flexibility create strategic opportunities. When Day-Ahead markets price in more scarcity than Real-Time delivers, the operators who can position accordingly (and maintain discipline through volatile periods) can optimize both system support and economics.

⏳  Short & sweet: big change as Day-Ahead goes 15-Minute Intervals ⌛ From 1 October 2025, the Single Day-Ahead Coupling (SDAC) will move from hourly (1h) to quarter-hour (15-min) trading intervals as mandated by EU law. That means the Day-Ahead auction at 12:00 CET will clear 96 slots per day instead of 24. 👉 Cross-product matching means 15, 30 and 60-min blocks still coexist 👉 A 60-min index price will continue to be published (the average of four 15-min results) Why it matters: 🌞 Solar ramps and wind swings can finally be priced more accurately 🔋  Batteries, EVs and flexible loads gain sharper signals 🤝 Traders face more volatility, but also more opportunities across DA, ID & Balancing But challenges are real: 📊 Stress tests showed up to 20% decoupling risk 🫗  Liquidity could thin out across 96 intervals 💰 Some “in-the-money” orders may still be rejected 📜  Contracts & PPAs (like the famous “6 negative hours” rule) may need rewriting 👻 Shadow auctions remain at hourly resolution, creating an odd dual system for fallback situations This isn’t just a niche change: it’s pan-European. Nearly all 27 SDAC countries are affected, from France, Germany and the Nordics to Spain, Italy and Eastern Europe. The only exceptions? Ireland & Northern Ireland, which remain on 30-min blocks. ⚡ Bottom line: A necessary reform to integrate renewables and flexibility, but also a major disruption if systems and liquidity aren’t ready. #EnergyMarkets #EPEX #DayAhead #Renewables #Flexibility #Trading #EUenergy

ISO-NE expected its new day-ahead reserves market to cost about $140 million a year. Year one came in at $974 million. The market launched in March 2025. It clears day-ahead energy and reserves together, so ISO-NE is not just buying energy for tomorrow; it is also paying resources to be available if real-time conditions get tight. Most of that cost came from the world changing after the estimate was made. Gas prices roughly doubled, from about $3/MMBtu to nearly $7/MMBtu, and day-ahead Hub prices rose from about $33/MWh to $71/MWh. Perhaps more interesting point is how concentrated the cost was. Twelve days drove roughly half of the first-year incremental cost. Five days during Winter Storm Fern, from January 25 to 29, accounted for about 40%. January 27 alone accounted for 18%. That is the chart. Most days barely move the needle. Then a handful of winter scarcity days carry the year. Combustion turbine outage rates fell from 18% before the market to 11% after implementation. Those units now earn about half their revenue from day-ahead ancillary services. The IMM is careful not to call that proof of causation, but the direction is clear: the market is paying flexible plants to be ready, and at least some of them appear to be responding. ISO-NE is now moving to adjust the design. The big proposed change is a fuel-cost-based floor in the strike price, targeted for late 2026. In normal hours, that should reduce the risk embedded in reserve offers and pull everyday DA A/S revenues lower. But it doesn't remove the basic shape of the opportunity. The money still concentrates in the same place: stressed days, high fuel prices, and tight winter operating conditions. So the battery question isn't “will DA A/S stay expensive every day?” It won't. But can you be positioned correctly before the handful of days and hours that decide the year?

The 15-minute energy prices will have a significant impact on the value of flexible production and consumption. This is good for you if you own a battery energy storage system or an Electric vehicle, and will be introduced throughout Europe on October 1st.   The average 15-minute prices might be equal to the 60-minute price, but I expect the price fluctuations within the hour to be of a similar magnitude to those we now see within a day.   The day-ahead market price is set by the marginal price of each period, so, naturally, prices will differ significantly within the hour as the availability of production differs.   Solar power production follows a ramp pattern, with the first 15 minutes having a lower volume than the last 15 minutes of the morning hours. The consumption is much more stable, meaning each morning hour starts with a high price and ends with a low price. Conventional generation cannot ramp up and down in this short time span, so the supply and demand curve will shift, impacting prices.   This is what should happen as the market moves closer to the physical reality with a more accurate pricing of the energy.   These price differences will significantly increase the value of flexibility and energy trading.   ☀️ For PV, it will result in even lower capture rates. 🔋 For a BESS, it means that there are four times more products to trade but probably ten times more spreads to deliver on. This will double the value that can be captured from the day-ahead market.   🚗 It can result in lower charging costs. Instead of charging your car for two hours straight, the optimal charging plan would spread the process over the best 15-minute periods throughout the night. It requires the charging optimiser to pause and restart the charging several times during the night to take advantage of the cheap periods. Optimal planning will increase in value compared to a fixed charging schedule.   Some of the Danish DSOs have been very slow at introducing 15-minute readings for the consumption customers. You may be settled on a 60-minute basis after October. In this case, the DSO will take your hourly consumption and spread it out equally in the 4 periods. In some cases, it might require a new meter, but the regulation states that everyone has the right to be settled at the same resolution as the market time unit. Hybrid Greentech - Energy Storage Intelligence

🚀 15-minute Day-Ahead market prices are finally here! Today marks the go-live of the 15-minute market time unit for the Single Day-Ahead Coupling (SDAC)! 🔍 What are we seeing from the first auction results? Prices are very similar to those in the IDA1 auction. The spiky price pattern familiar from IDA1 is also visible in the new 15-minute Day-Ahead results. This is likely a short-term effect, as many market participants haven’t yet adapted their internal processes to the new format. I expect these spikes to gradually soften over the coming months as the market adjusts. 📊 Volume shifts are already happening: Day-Ahead volumes increased by 5%, showing early adoption. IDA1 volumes dropped by 37%, as traders shift to the new 15-minute Day-Ahead product. However, many still trade the hourly Day-Ahead product, as seen in the volume distribution — clear hourly steps remain. 💡 What does this mean for business cases in Germany? Batteries: In the short-term, there are more trading opportunities due to the introduction of the (still volatile) 15-minute Day-Ahead product, increasing the revenue potential. However, if the spikiness fades, a easy arbitrage opportunity may disappear in the medium to long term. Renewables: The biggest question is whether the 15-minute blocks will increase the generation which occurs during negative prices. We’ll likely need to wait until next spring to find it out. ⚡️ The transition is underway, but full market adaptation will take time. It’s a fascinating moment to watch how trading behaviour evolves and what this means for flexibility assets and renewables. #EnergyTrading #SDAC #15minMarket #Germany #PowerMarkets #Renewables #Batteries #MarketDesign #EnergyTransition