How Energy Mix Affects Pricing

Little game for my kids, and everyone else. Comparing two electricity markets, one with a price peak in the evening, the other without. Which color, or technology is missing in the power mix in Germany? Earlier this week we have seen an arrival of a kind of new phenomena in our energy system: peak power prices in the summer. Driven by increasing AC-loads and climate change related lower capacity factors of European nuclear and fossil power fleets, prices peak in the evening. You can find a nice write down of this by Matthias Janssen here: https://lnkd.in/ehymPvCK Before somebody tells us, that this is a clear sign that we need to build (let's pick a random number) 20 GW of gas peakers as soon as possible (to at least a Schnellboot) ... or bring back coal plants from the grid reserve ... let's ask ourselves, how are other markets dealing with this. A peak price period of 4 hours, plannable, and right after a day with plenty of renewables at negative power prices. Wouldn't it be great, if we could 😵 STORE electricity? The comparison with CAISO (California) painfully shows what is missing in the German (and European) power mix. In CAISO, on June 30th at a load of 31 GW, BESS delivered 10GW of peaking power, keeping gas peakers offline. The power prices in the evening never went above $100/MWh. In Germany without BESS to dispatch at scale gas peakers ramped up, burning expensive fuel and putting their start up cost for only limited hours of operation into the market bid, resulting in a power price of 476€/MWh. In fairness, around 5.4 GW of pumped hydro plants were dispatched at the same time, mirroring what a large BESS fleet would do during this time. Clear and simple message: If you want to prevent high peak power prices, allow flexibility into your power mix. BESS is the only technology class that is being build in Germany without subsidies or state-supported revenue guarantees. But policy makers, regulators and grid operators on many fronts try to slow down the single success story of the German power market (from an investment site). Some just want to build gas plants, others are overwhelmed with lacking digitalization of their grids and the regulator just wants to squeeze as much money as possible from the business case of batteries. But bottom line, the CAISO example shows us, what our future power mix should look like, and that BESS are the key tool to provide peaking power and reduce scarcity pricing in power markets.

Thinking about the changing energy resource mix and how it impacts electricity prices. In pursuit of insights, it’s helpful to think through edge cases. One is a grid powered by 100% #renewableenergy and energy storage. A recent study by the Leibniz Information Centre for Economics looks at 2 markets, Texas (ERCOT) & Germany, and explores if energy-only markets can function with a resource mix of only #wind, #solar, Demand Response (DR) and storage. Will capacity mechanisms be needed in markets after the energy transition? Can a healthy market exist with energy storage as the only firm capacity? Yes, they conclude, energy-only markets remain perfectly viable even when exclusively #windenergy, solar, DR, and #energy storage. Using cost scenarios based on 2020 data and 2050 forecasts, they find average market prices in #ERCOT are reasonable and could become lower. What happens to the merit order (the electricity supply curve of suppliers in order of their marginal cost)? The figure below shows the new merit order for ERCOT and the residual demand / energy storage utilization. The merit order looks like today’s: relatively few hours have zero prices, a vast middle section has positive prices (mostly $40-$50/MWh), and peak price periods still exist and are an essential element for fixed-cost recovery. In the new merit order, storage plays a critical role because it often sets prices on both the buy and sell sides, thus sets the market price for #electricity. Other interesting ERCOT results: ·       Changes in wind and solar costs from 2020 to 2050 would raise the optimal capacity ratio of solar to wind capacity from about 0.6 to 2.0. ·       In 2050, solar’s share of ERCOT’s power output would need to increase from 3% to 61%, while wind output would need to increase from 23% to 39%. ·       The nominal capacity ratio of storage to wind + solar is about 0.28. Some limitations of the modeling: ·       No explicit transmission infrastructure in the model (i.e., no transmission constraints). ·       Ancillary services still need to be priced separately and are not considered. ·       The duration of storage (MWh) is not accounted for, only power capacity (MW). ·       No negative pricing was allowed. Two additional thoughts: In very high renewable, energy-only markets, where fossil fuel plants are not allowed or available, average energy prices should converge on the Levelized Cost of Storage (LCOS, i.e., the cost per cycle of storage needed to cover all costs and investment returns for the life of the project). Lazard’s most recent analysis shows stand-alone storage LCOS at $124/MWh for 100 MW/ 400MWh BESS, and this needs to – and will – come down in the next decade (it’s $60/MWh and $45/MWh respectively, for solar and wind hybrids). Also, curtailment (or negative pricing) is not necessarily a market flaw - it can offset lower and fewer peak pricing events by allowing #energystorage to charge at zero cost (or less).   References in comments.

I recently built this chart comparing 2024 residential electricity rates by U.S. state. States are color-coded by their 2024 presidential voting preference—blue for Democratic, red for Republican, and purple for swing states—to explore whether policy environments might correlate with power costs (or vice versa??). The pattern is statistically striking: states that lean Democratic tend to have higher retail electricity prices, while Republican-leaning states cluster toward the lower end, with swing states distributed near the national average. Regional resource mix: Northeastern states have poor renewable resources and rely more on imported fuels because of their aging infrastructure and lack of pipeline capacity to natural gas producers in the Marcellus. Much of the South and Midwest benefit from proximity to low-cost natural gas, coal, and wind resources. Infrastructure permitting and interconnection timelines: Regulatory and siting processes vary dramatically—California’s interconnection queue in CAISO averages around seven years, versus roughly two years in ERCOT (Texas). Longer lead times increase carrying costs and delay capacity additions. Outliers: Alaska’s isolation and climate drive its high prices, while hydropower abundance in Washington and Oregon suppresses rates below the national average.

Are Renewables Really Driving Up Electricity Prices? If you're reading this, I'm guessing you've seen that chart claiming: "The more solar and wind you have, the more expensive electricity gets!" Like me, you might scratch your head. Classic correlation ≠ causation. 💡 If renewables are inherently expensive, why are they still being built everywhere? IEA, BloombergNEF, and even BP agree that new wind and solar are the cheapest form of new capacity in most markets. That first graph oversimplifies. The second chart shows it's more complex - electricity pricing is about more than generation costs. It is worth taking a closer look. 💡 Europe vs. the U.S.: Different Price Trends In Europe, prices are higher alongside renewables because of myriad reasons. These include: Higher baseline energy taxation funding social programs Carbon pricing Early feed-in tariffs locked in higher rates to speed adoption Massive grid upgrade investments to cover more renewables Indeed, in 2024, EU electricity prices declined significantly due to reduced fossil use and cheaper gas/coal, though legacy infrastructure fees remain a challenge. The EU is now introducing policy measures (e.g., the Action Plan for Affordable Energy) to bring rates down. Meanwhile, many U.S. states with high renewables show lower prices because: Later adoption at lower technology costs Competitive markets driving down prices Abundant land resources In addition to fewer taxes and fewer public services ⚡ California vs. Texas: Same Renewables, Different Prices Both have similar renewable percentages, yet California's prices are nearly double. California's Higher Prices Are Also Not So Simple: Wildfire investments – Billions spent upgrading infrastructure, to prevent blackouts during emergencies Aging grid – Deferred maintenance costs catching up Gas dependency – Reliance on volatile natural gas prices Regulatory structures Early transition costs – Initial grid upgrades Net Metering – Fixed grid costs spread over fewer rate payers Texas Keeps Prices Low With: Free-market policies driving cheap wholesale prices Fewer mandated resilience investments Competitive renewable procurement Iowa and South Dakota offer more proof - higher renewable shares than Germany or Denmark but less than half the electricity prices. 🚀 The Takeaway: Renewables Are Cheap—Legacy Costs Aren't High-renewable regions with high prices are driven by: 🔹 Infrastructure investments 🔹 Market design & outdated pricing 🔹 Lingering fossil fuel dependence Renewables themselves are the cheapest new power source globally—it's the transition costs that muddy the picture. So, the next time someone says "Renewables raise electricity prices," ask them: 👉 "Then why are new wind and solar the cheapest power options available?" #Energy #Renewables #GridResilience #ElectricityPrices #Decarbonization #StorageSolutions #SustainableEnergy #FutureOfEnergy #PowerMarkets #EnergyTransition

When the duck curve turns into an all-day plateau, industrial consumers need either fuel-switching options or long-duration storage to stay competitive. Today’s day-ahead prices in the DE-LU bidding zone look very different from the usual pattern. The typical midday dip is missing; instead, prices stay high from early morning until late evening. With an average of 220.5 €/MWh, 25 November now ranks as the third most expensive trading day of 2025, surpassed only by two extreme days in January. And the situation is not easing: the forecast for 26 November remains only marginally lower. 𝐖𝐡𝐲 𝐩𝐫𝐢𝐜𝐞𝐬 𝐫𝐞𝐦𝐚𝐢𝐧 𝐞𝐥𝐞𝐯𝐚𝐭𝐞𝐝 𝐟𝐨𝐫 𝐯𝐢𝐫𝐭𝐮𝐚𝐥𝐥𝐲 𝐭𝐡𝐞 𝐞𝐧𝐭𝐢𝐫𝐞 𝐝𝐚𝐲 A set of reinforcing factors compresses the price curve upward: ➤ Weak wind and solar generation limit supply across all hours. ➤ Low temperatures keep the residual load above 65 GW, even during midday. ➤ Structural scarcity in dispatchable capacity, as recently highlighted by Andri Busch. On top of that: once short-duration storage is exhausted, demand becomes largely inflexible, reducing the system’s ability to respond to price spikes. ➤ Additional contributors may be at play, potentially including local market power effects. The outcome is a remarkable spread between electricity and natural gas: for several consecutive hours, power prices exceed ten times the gas spot price (~32 €/MWh). 𝐖𝐡𝐚𝐭 𝐭𝐡𝐢𝐬 𝐦𝐞𝐚𝐧𝐬 𝐟𝐨𝐫 𝐢𝐧𝐝𝐮𝐬𝐭𝐫𝐢𝐚𝐥 𝐞𝐧𝐞𝐫𝐠𝐲 𝐮𝐬𝐞𝐫𝐬 Industries with substantial process-heat requirements face a simple fact: without a non-electric heat source or a high-temperature, long-duration storage asset, they are forced into producing heat at highly unfavorable electricity prices. Both strategies, fuel-switching or long-duration storage, are becoming critical elements of cost resilience. 𝐖𝐡𝐲 𝐬𝐭𝐨𝐫𝐚𝐠𝐞 𝐝𝐮𝐫𝐚𝐭𝐢𝐨𝐧 𝐦𝐚𝐭𝐭𝐞𝐫𝐬 In a renewables-driven system, short-duration storage smooths volatility but does not compensate for system-wide generation deficits spanning an entire working day. When price plateaus persist for eight hours or more, only technologies capable of shifting energy across multi-hour to multi-day intervals can stabilise operations and costs. These include: ➤ Long-duration thermal storage ➤ Hydrogen-ready or hybrid plants ➤ Other forms of long-duration energy storage (LDES) Days like today make one point unambiguously clear: flexibility is not solely about rapid response. It is about endurance. A renewables-based system requires assets that can maintain supply through extended scarcity periods without defaulting back to additional fossil capacity. Brenmiller Energy ENERGYNEST KRAFTBLOCK Kyoto Group AS Rondo Energy et al.

Electricity prices across the globe are shaped by a variety of factors, including the energy mix, market design, and policy frameworks. A critical component of this discussion is the role of RE, particularly its impact on affordability and grid stability. While renewable energy is essential for achieving decarbonization, the type and role of RE in the energy mix are crucial in determining its effect on electricity prices. Countries with significant baseload renewable energy sources, such as hydropower or geothermal, demonstrate how a high share of RE can coexist with low electricity prices. #Brazil and #Canada are prime examples, leveraging their abundant hydropower resources to maintain stable, affordable energy systems. These baseload renewables provide consistent power, reducing reliance on fossil fuels and minimizing the need for costly backup systems. In contrast, nations heavily reliant on variable renewable energy (vRE), such as wind and solar, often face higher electricity prices. This is particularly true for countries like #Germany and the #UK, where the integration of vRE has introduced higher grid management costs, the need for backup capacity, and increased investments in storage and infrastructure. Without sufficient baseload capacity—whether from renewable sources like hydropower and geothermal, fossil fuels, or nuclear power—vRE's intermittency can strain the grid and drive up prices. #Nuclear energy emerges as a strategic alternative for countries without access to renewable baseload resources. Its ability to provide reliable, low-carbon baseload power makes it an effective partner for balancing the intermittency of vRE. #France, for instance, demonstrates how nuclear energy can help maintain lower electricity prices while supporting decarbonization goals. The lesson is clear: to ensure affordable and sustainable energy systems, countries must prioritize renewable baseload options like hydropower and geothermal wherever possible. For nations without these resources, nuclear energy offers a viable alternative to support grid stability and price control. Overreliance on vRE without adequate baseload—whether from renewables, fossil fuels, or nuclear—can lead to inefficiencies, higher costs, and energy insecurity. The path to a cleaner, more affordable energy future is not one-size-fits-all. Each country must craft an energy mix tailored to its resources and needs, balancing sustainability with economic practicality. By prioritizing baseload RE and strategically integrating vRE, nations can achieve a stable, affordable, and sustainable energy transition. Lars Schernikau | Bob S. Effendi | Kei Sudo | Zulfikar Yurnaidi | Alloysius Joko Purwanto | Dr. Intan Murnira Ramli | Razib Dawood | Putra Adhiguna | Alex Hong | Andy Tirta | Ahmad Yuniarto | Darmawan Prasodjo | Sho Hayashi | weerawat chantanakome | Peerapat Vithayasrichareon | ERIA: Economic Research Institute for ASEAN and East Asia ASEAN Centre for Energy

Why Are Energy Bills Still High? I came across a BBC article discussing why energy bills in the UK are still high. I've covered this topic before, but here’s a recap: The UK’s energy price is made up of several key components: 👉 Wholesale Power Price - This is the price suppliers pay in the market, set by marginal pricing. The cost of the last unit of power needed to meet demand determines the price. This is invariably set by gas, which, due to its cost structure, has a major influence on overall prices. 👉 Social & Environmental Costs - These cover support schemes like Contracts for Difference (CfD) and the Capacity Mechanism (CM). CfD helps support renewable energy technology by guaranteeing a price per kWh, the Strike Price. If the wholesale price is higher than the Strike Price, the generator pays back into the scheme, if lower the consumer covers the short fall through a levy. Capacity Mechanism ensures generators are available, through capacity payments, during system stress events, providing a level of grid security. 👉 Network Charges - These charges cover the cost of operating, maintaining, and upgrading local distribution networks—the physical wires that carry electricity to homes. Network Charges also include Balancing Charges from the Balancing Mechanism, covering actions to balance the system by NESO, either paying generators to increase or decrease generation. Also includes costs to curtail wind due to lack of local demand and north to south transmission constraints. 👉 Operating Costs & Supplier Profit - A fixed cost applied by the supplier to cover their own operational expenses. The article mentions that as more renewables come online, there should be more instances where gas doesn’t set the wholesale price but the wholesale price is only one part of the utility, see pie chart below 👇 👉 The Future of Gas in the Energy Mix. 💡 Transitioning to a system with less reliance on gas and more renewables will require lots of energy storage, something we currently lack. With plans for 43-50 GWe of offshore wind, 27-29 GWe of onshore wind, and 45-47 GWe of solar power, it’s hard to see how gas won’t remain a key player for grid balancing, especially during peak demand periods and continue to be the marginal generator. Case in Point 8th Jan 2025. 💡 The hot topic of Zonal Pricing only looks to remove the link to gas and power price in areas which have high renewable concentration. ⁉️ What are your thoughts? Do you see gas continuing to play a key role in the energy mix as we move toward 2030 clean power targets? BBC article link in comments 👇 Pie Chart for illustration only.

🌍💡 These short-term high electricity prices could have been higher and could have lasted longer. Right now in Northern Europe, we're facing relatively high electricity prices due to low wind and solar PV production, influenced by low-pressure weather systems. This situation has sparked questions about whether our energy transition is the right path. What is the bigger picture? 📉 Prices are dropping overall Despite current fluctuations, electricity prices in 2024 are about 10% lower than they were in 2023. Yes, they’re still higher than pre-COVID levels in 2020, but the trend is moving in the right direction. This is a clear sign that our policies to expand renewable energy are paying off. In Denmark alone, we’ve seen over 360 hours of negative electricity prices, and renewables now make up a higher proportion of Europe’s electricity mix than fossil fuels. This year, many EV owners across Europe have charged their vehicles at zero, low, or even negative electricity prices, thanks to the increasing availability of wind and solar power. 💨 Renewables outpacing fossil fuels Coal and natural gas prices are higher than before the energy crisis started. If we had less renewable energy, these commodities would set the prices in even more hours. The higher prices currently is also connected to a very high waste full use of electricity for heating in the Nordics. This increases the electricity consumption. 🔄 What’s next? As the REPowerEU initiative continues to expand the share of renewables, we can expect stabil or lower average electricity prices, although seasonal fluctuations will remain and most likely increase. More renewable hours mean fewer times when coal and natural gas set the market prices. The vision is to gradually replace these fossil fuels with flexible market players based on e.g. biogas, providing stability to the electricity market. We do not need baseload power, but we do need capacity in the power sector for 10-20% of the time 🌞💨 #EnergyTransition #RenewableEnergy #EuropeanEnergy #Sustainability #ElectricityPrices #CleanEnergy #FutureOfEnergy #GreenEurope #REPowerEU

𝗟𝗼𝘄𝗲𝘀𝘁 𝗽𝗿𝗶𝗰𝗲 𝘀𝘁𝗶𝗹𝗹 𝘄𝗶𝗻𝘀 — 𝗯𝘂𝘁 𝘁𝗵𝗲 𝗽𝗿𝗼𝗱𝘂𝗰𝘁 𝗵𝗮𝘀 𝗰𝗵𝗮𝗻𝗴𝗲𝗱 In a recent post (https://lnkd.in/gvrvVXV7), I mentioned: “The game is changing: from ‘who’s cheapest’ to ‘who’s most certain’” for grid evening peak prices. Discussions made me realise that the logic behind this shift needed more clarity. 𝗧𝗵𝗲 𝗰𝗼𝗻𝗰𝗹𝘂𝘀𝗶𝗼𝗻 𝗶𝘀 𝘀𝗶𝗺𝗽𝗹𝗲:  “Lowest price wins” remains unchanged. What has changed is the product itself. As renewables grow, evening peaks become both more frequent and harder to predict. Think of two segments:  - Predictable part (𝗦𝗰𝗵𝗲𝗱𝘂𝗹𝗲𝗱 𝗰𝗹𝗶𝗻𝗶𝗰): predictable demand, booked in advance.  - Unpredictable part (𝗘𝗺𝗲𝗿𝗴𝗲𝗻𝗰𝘆): unpredictable demand, revealed minutes before, requiring instant readiness. Gas still carries a share in the predictable part (around 20% in the chart I shared earlier). BESS appears mainly in the unpredictable part. 𝗪𝗵𝘆 𝗱𝗼𝗲𝘀 𝘁𝗵𝗲 𝘂𝗻𝗽𝗿𝗲𝗱𝗶𝗰𝘁𝗮𝗯𝗹𝗲 𝘀𝗲𝗴𝗺𝗲𝗻𝘁 𝗻𝗼𝘁 𝘀𝗲𝗲𝗺 𝘁𝗼 𝗳𝗼𝗹𝗹𝗼𝘄 “𝗹𝗼𝘄𝗲𝘀𝘁 𝗽𝗿𝗶𝗰𝗲 𝘄𝗶𝗻𝘀”? Because the product is different. - In the 𝗽𝗿𝗲𝗱𝗶𝗰𝘁𝗮𝗯𝗹𝗲 𝗽𝗮𝗿𝘁, buyers purchase 𝗵𝗼𝘂𝗿-𝘀𝗰𝗮𝗹𝗲 energy. Gas is still cheaper, so it wins. - In the 𝘂𝗻𝗽𝗿𝗲𝗱𝗶𝗰𝘁𝗮𝗯𝗹𝗲 𝗽𝗮𝗿𝘁, buyers purchase certainty of 𝗺𝗶𝗻𝘂𝘁𝗲-𝗹𝗲𝘃𝗲𝗹 delivery. Gas cannot always ramp quickly and incurs costs from technical constraints. BESS responds instantly and avoids waste. 𝗥𝗲𝘀𝘂𝗹𝘁: BESS gains the marginal role and pricing influence in the emergency window. With more renewables, this window grows in size and frequency, so storage gains bargaining power. ✅ 𝗧𝗮𝗸𝗲𝗮𝘄𝗮𝘆  “Lowest price wins” has not changed; what has changed is what is being bought. Predictable = scheduled clinic, priced by cost; unpredictable = emergency, valued by certainty.  As this emergency share grows in the evening peak, BESS naturally moves to the margin and gains bargaining and pricing power. 🤔 𝗤𝘂𝗲𝘀𝘁𝗶𝗼𝗻  Are we clear about what is actually being purchased in peak markets? #TechToValue #EnergyStorage #EnergyMarkets