Energy Market Management

Solar created the duck curve. Batteries are now flattening it. This chart shows median wholesale electricity prices in New South Wales during the second quarter of each year. In 2023, prices surged towards $300/MWh during the evening peak. In 2026, that peak is below $100/MWh. While the chart shows NSW, this same pattern is emerging across Queensland, Victoria and South Australia as well. The driver of this is becoming familiar: batteries. ✅ Batteries create demand during solar-rich daytime hours, preventing midday prices from falling as deeply. ✅ They discharge after sunset, adding supply when evening demand rises. ✅ This reduces reliance on gas and hydro during the evening peak, when they have traditionally set higher prices. The scale of the battery build-out is now large enough to reshape both electricity supply and demand. Modo estimates that registered home-battery power capacity across Australia's National Electricity Market has reached 7.8 GW, overtaking the 7.7 GW of operational grid-scale batteries. Those home batteries increasingly charge during solar-rich daytime hours, then meet household demand after sunset - reducing grid demand. Meanwhile, grid-scale batteries add supply directly into the evening market. Batteries are also increasingly determining the wholesale price. In Q2, battery charging and discharging set prices in 36% of NEM dispatch intervals, up from 17% a year earlier. During the evening peak, battery discharge was the dominant price-setter. The curve is therefore being flattened from both directions: more demand when solar is abundant and more supply when evening demand rises. As battery capacity grows, the gap between the cheapest and most expensive hours is narrowing. That means lower peak prices, less volatility and a more productive use of daytime solar.

This has been a difficult winter for European electricity. The rise in wholesale prices has been sharp and widespread—it is not restricted to a few hours, or to one corner of the Continent, or to days when something unusual happens. The weighted average price across the EU exceeded 100 €/MWh in both November and December, returning to levels not seen since early 2023. January 2025 does not look much better so far. The primary driver of European electricity prices on a day-to-day basis is the volatility of wind. But wind exerts this influence because of broader shifts in the system. Nuclear remains far below its peak, and coal has declined sharply. Output from hydro is low, in some places acutely so. Solar delivers very little during the winter, and even less on cloudy and rainy days. In other words, the European system is short. It is very short when the wind does not blow, it is mostly short in the evening no matter what, and it is mildly short during other times (it is rare to see negative or zero prices outside a few key countries). We then use gas to close the gap, triggering a vicious cycle between tight gas markets and tight electricity markets. The result is high electricity prices during most hours and extreme prices during some hours. This is hardly a stable equilibrium. We talk a lot about flexibility—and rightly so. But flexibility is often defined in short intervals—a few hours or maybe a few days, leading us to emphasize solutions like storage or demand response. We rarely test scenarios based on the data in this chart, and we rarely model the interactions among systems that are making decisions quite independently from one another. Extreme prices are distress signals. They are telling us capacity is missing. And they are telling us that whatever governance system we are using to oversee this complex, EU-wide system is not enough. The path to lower prices lies not just with deploying more renewables and more storage, but also in solving this complex governance puzzle. It is the only way to guarantee resource adequacy without resorting to a steady stream of exorbitant prices.

⚡ Ten days. That’s all it took for Germany’s 15-minute market to expose our next big energy problem. When Germany switched from hourly to 15-minute spot market prices, it wasn’t just a technical change. It was like turning up the sensitivity dial on the entire energy system. Suddenly, the grid started telling us the truth… every 15 minutes. And it’s fascinating what that truth looks like. 1️⃣ Prices now move with the weather Every passing cloud, every burst of sunshine, you can see it reflected in the market. Prices spike, dip, recover, all within minutes. It’s messy, yes. But it’s also honest. 2️⃣ Flexibility has become the real star In a world that moves every 15 minutes, flexibility isn’t a nice-to-have. It’s everything. Batteries, smart EV charging, flexible industrial loads… These aren’t “future tech” anymore. They are what keep the grid balanced in real time. 3️⃣ Renewables are setting the rhythm Midday prices drop when solar floods the grid. Evenings see the classic ramp-up as the sun fades but demand stays high. The market is finally dancing to the rhythm of the sun and wind. 4️⃣ The Flexibility Gap is showing There are a few moments, very few (marked in golden circles), when renewables actually exceed demand. Those moments whisper: “We could have run on 100% renewables… if only we had more flexibility.” Storage, smart demand, and hydrogen can turn those whispers into everyday reality. 5️⃣ Efficiency is quietly improving More granular trading means fewer mismatches, less waste, and better alignment between generation and demand. The system is learning to breathe more naturally, in smaller, faster rhythms. 6️⃣ It’s not just about power anymore. It’s about timing. In a 15-minute market, the question isn’t “how much energy do we have?” It’s “when do we have it?” That’s a mindset shift for utilities, for industry, and for all of us watching this transition unfold. 💭 My takeaway Germany’s 15-minute market is teaching us that the energy transition doesn’t just need clean power. It needs quick reactions. We’ve built renewables. Now we need to build flexibility. Because in this new world… every 15 minutes counts. ⚡

Rising EU gas prices drive European power prices: Europe’s “merit order” ranks power plants by their marginal (variable) costs for producing a single MWh of #electricity. To economically optimize the available electricity supply, the cheapest power suppliers produce first (#solar, #wind and hydro with marginal production costs of close to zero), while the most expensive power plants (#gas or coal) produce the last MWh of electricity to clear the market (see upper chart). Thereby, the most expensive power plant (gas) sets the electricity price for all power plants involved, even for those with zero marginal production costs (solar, wind and hydro). This is called “uniform pricing” because all power plants receive the same price for their supplied electricity. This merit order principle explains why EU gas prices set electricity prices and why both prices are highly correlated in Europe. As EU gas prices (TTF) have hit EUR 58/MWh (highest level since Jan 2023), German wholesale electricity prices have also started to rise and have mostly stayed above EUR 100/MWh in 2025, which is still significantly below the 2022 peaks after the Ukraine war started (see lower chart). Which companies could benefit? RWE, which captures Europe’s rising electricity prices in two ways: first, about half of its generated solar, wind & hydro power (41 TWh) is sold in Europe at zero marginal costs and second, its flexible gas power generation (42 TWh in 2023) captures the price spikes, when gas plants have to step-in during the so-called “Dunkelflaute” (when the wind does not blow and the sun does not shine) #energy

💸 Why flexibility and storage will drive down European Energy prices: Understanding marginal pricing in energy markets. In the world of energy markets, marginal pricing is a critical concept that determines the cost of electricity. It works by setting the price based on the cost of the last unit of electricity produced to meet demand. This often means that the price is set by the most expensive source of energy, which is typically fossil fuels. As noted in the JRC134300 publication, "marginal pricing ensures that the price reflects the cost of the last unit needed to meet demand" . 🔍 The Paradox of Renewable Curtailment Despite their near-zero marginal cost, renewable energy sources like wind and solar are being curtailed in many countries. This happens when the supply of renewable energy exceeds demand or when grid constraints prevent its integration. As a result, we miss out on the opportunity to utilize clean energy, and the marginal price remains influenced by fossil fuels. The publication highlights that "curtailment of renewables occurs even though they have a near-zero marginal cost" . According to Figure 14 in this Joint Research Center report (https://lnkd.in/dPgZwGwd) , by 2030, fossil fuels will represent a small fraction of the total generation mix. However, they will still often be the price-setting technology, thereby driving energy prices in Europe. This underscores the need for strategic interventions to mitigate this impact. ⚡ The Power of Flexibility Introducing flexibility into the energy system can change this dynamic. By leveraging energy storage and demand response, we can store excess renewable energy and use it when needed, reducing the reliance on fossil fuels to set marginal prices. This not only optimizes the use of renewables but also stabilizes energy prices. The report suggests that "flexibility can drastically reduce the time marginal price is set by fossil sources" . It's time to promote flexibility and storage solutions even more aggressively. By doing so, we can harness the full potential of renewable energy, reduce our carbon footprint, and create a more resilient energy system. #MarginalPricing #BESS #Flexibility #EnergyStorage #Curtailment #CleanIndustrialDeal

𝗣𝗲𝗮𝗸 𝗡𝗲𝘁 𝗟𝗼𝗮𝗱: 𝗧𝗵𝗲 𝗡𝗲𝘄 𝗥𝗲𝗮𝗹𝗶𝘁𝘆 𝗧𝗵𝗮𝘁’𝘀 𝗥𝗲𝘀𝗵𝗮𝗽𝗶𝗻𝗴 𝗘𝗻𝗲𝗿𝗴𝘆 𝗠𝗮𝗿𝗸𝗲𝘁𝘀 For years, energy planning was fairly predictable. Peak demand meant peak prices. Utilities and businesses could plan accordingly, relying on fossil fuels and nuclear plants that ran on well-understood schedules. But that world no longer exists. Today, 𝗽𝗲𝗮𝗸 𝗻𝗲𝘁 𝗹𝗼𝗮𝗱 is the amount of electricity demand that must be met by non-intermittent resources after subtracting renewable generation, has upended traditional forecasting. And for businesses, this shift can mean the difference between saving millions or getting blindsided by price volatility. 𝗧𝗮𝗸𝗲 𝗘𝗥𝗖𝗢𝗧 𝗶𝗻 𝗔𝘂𝗴𝘂𝘀𝘁 𝟮𝟬𝟭𝟵: 🔹 August 12 saw higher demand but lower prices, because wind generation was strong. 🔹 August 15 had lower demand but skyrocketing prices, because wind generation was weak. 𝗧𝗵𝗲 𝗹𝗲𝘀𝘀𝗼𝗻? It’s no longer just about peak demand, it’s about what’s actually available when you need it. 𝗧𝗵𝗶𝘀 𝗻𝗲𝘄 𝗿𝗲𝗮𝗹𝗶𝘁𝘆 𝗰𝗵𝗮𝗻𝗴𝗲𝘀 𝘁𝗵𝗲 𝗴𝗮𝗺𝗲: ✅ 𝗠𝗼𝗿𝗲 𝘃𝗼𝗹𝗮𝘁𝗶𝗹𝗶𝘁𝘆 – Prices now swing based on renewable output, not just demand. ✅ 𝗛𝗮𝗿𝗱𝗲𝗿 𝗳𝗼𝗿𝗲𝗰𝗮𝘀𝘁𝗶𝗻𝗴 – Traditional models struggle to predict price spikes. ✅ 𝗛𝗶𝗴𝗵𝗲𝗿 𝗿𝗶𝘀𝗸 – Businesses must rethink energy procurement and hedging strategies. 𝗧𝗵𝗼𝘀𝗲 𝘀𝘁𝗶𝗹𝗹 𝗽𝗹𝗮𝗻𝗻𝗶𝗻𝗴 𝗮𝗿𝗼𝘂𝗻𝗱 𝘆𝗲𝘀𝘁𝗲𝗿𝗱𝗮𝘆’𝘀 𝗲𝗻𝗲𝗿𝗴𝘆 𝗿𝘂𝗹𝗲𝘀 𝗮𝗿𝗲 𝗹𝗲𝗮𝘃𝗶𝗻𝗴 𝘁𝗵𝗲𝗺𝘀𝗲𝗹𝘃𝗲𝘀 𝗲𝘅𝗽𝗼𝘀𝗲𝗱. 𝗧𝗵𝗲 𝗳𝘂𝘁𝘂𝗿𝗲 𝗯𝗲𝗹𝗼𝗻𝗴𝘀 𝘁𝗼 𝘁𝗵𝗼𝘀𝗲 𝘄𝗵𝗼 𝘂𝗻𝗱𝗲𝗿𝘀𝘁𝗮𝗻𝗱 𝗮𝗻𝗱 𝗮𝗱𝗮𝗽𝘁 𝘁𝗼 𝘁𝗵𝗲 𝗱𝘆𝗻𝗮𝗺𝗶𝗰𝘀 𝗼𝗳 𝗽𝗲𝗮𝗸 𝗻𝗲𝘁 𝗹𝗼𝗮𝗱. How is your business navigating this? Drop a comment below. 👇 * * * * * * * * * * 𝗗𝗼𝗻'𝘁 𝗷𝘂𝘀𝘁 𝘂𝘀𝗲 𝗯𝗲𝘁𝘁𝗲𝗿 𝗲𝗻𝗲𝗿𝗴𝘆, 𝘂𝘀𝗲 𝗲𝗻𝗲𝗿𝗴𝘆 𝗯𝗲𝘁𝘁𝗲𝗿!™ For energy insights, follow: #EnergyNinjaChronicles ⚡ Subscribe to the newsletter: 📩 https://lnkd.in/dGpq2-dC #EnergyMarkets #PeakNetLoad #EnergyRisk #ERCOT #EnergyIntelligence

The Iran war is increasing the risk that global energy supply disruptions will spill into U.S. natural gas markets and, in turn, the wholesale power prices that underpin PPA valuations. Oil and gas infrastructure across the Gulf is being attacked. Qatar halted LNG production/liquefication and declared force majeure on shipments, removing the 2nd largest exporter from the market. And the Strait of Hormuz is blocked, choking ~20% of global LNG trade. These developments have sharply repriced natural gas risk. Gas markets are more on edge today than at any point since Russia’s 2022 invasion of Ukraine, when U.S. gas prices spiked to the highest levels in over a decade. Overseas, Europe’s benchmark gas price surged to three-year highs. For now, the immediate impact on U.S. gas has been limited. But that relative calm may prove misleading. And this war may have a significant impact on PPA performance and valuations. Natural gas pricing is critical to track because gas remains the dominant marginal fuel in many U.S. wholesale power markets. Gas-fired plants convert natural gas into electricity at a specific efficiency ratio, commonly referred to as a “heat rate.” E.g., if gas costs $3/MMBtu and is converted to electricity at a 7x heat rate – that plant will offer at least $21/MWh into the wholesale power market. Since wholesale power markets are dominated by gas-fired generation, those facilities often set the marginal price of electricity. In PJM, gas-fired gen sets the marginal price ~80% of the time. Power prices have correlated so closely with natural gas prices that traders use long-dated natural gas futures as a proxy hedge when power market liquidity is limited. In summary, gas prices feed directly into spot power prices, power forward pricing, and merchant curves - the foundations for valuing PPAs. As such, a sustained geopolitical premium in gas can materially affect PPA economics. This matters a lot today. The U.S. is highly exposed to global gas dynamics through LNG exports. The U.S. has little spare LNG capacity available in the near term and much of output is contractually committed, limiting our ability to replace lost Qatari cargoes immediately, which may help suppress near-term prices. But export capacity is expected to double by 2031, and our ability to quickly respond to global demand spikes will allow more gas to be diverted to international use, deepening the long-run connection between global gas shocks and domestic power pricing. CME Henry Hub futures are already pricing in materially higher domestic gas prices, rising from ~$3/MMBtu for Apr 26 delivery to roughly $5/MMBtu in Dec. The takeaway is straightforward: geopolitical risk is no longer just a foreign policy story or an oil market story. It is increasingly a U.S. power market story, with direct implications for forward curves, merchant risk, and the value of renewables deals.