Energy Market Insights

The latest reporting from the Financial Times highlights a point that energy analysts have been making for years: geopolitical shocks consistently strengthen the case for renewables, electrification and storage. Microsoft’s global vice-president for energy notes that oil and gas price spikes linked to the Middle East conflict reinforce the value of wind, solar and batteries in providing price stability. Once installed, renewables offer predictable cost profiles and reduce exposure to volatile global fuel markets. We saw this dynamic after Russia’s invasion of Ukraine. Europe accelerated solar deployment, heat pump uptake increased in several countries, and governments revisited questions of energy security through the lens of diversification and electrification. The underlying issue remains unchanged. Fossil fuels must continuously flow through complex global supply chains. When those flows are disrupted, prices spike and economies are exposed. Renewables, by contrast, are capital intensive upfront but deliver long term domestic supply and insulation from commodity shocks. There are short term risks. Inflation, higher interest rates and supply chain constraints can slow clean energy investment. Some governments may also respond by doubling down on gas infrastructure. The policy challenge is to avoid locking in further structural vulnerability. Energy security and climate policy are not competing objectives. In a world of recurrent geopolitical instability, they are increasingly aligned.

During my time serving in government, I saw firsthand how geopolitics can impact energy production and flows, with cascading impacts on market and macroeconomic trends.   We're already seeing this play out following the last few days in the Middle East. U.S. and Israeli strikes on Iran triggered retaliatory action across the region that has disrupted energy production and transit.   The market reaction is changing quickly. Since I recorded this video on Monday, oil and gas prices have jumped further, and equities have shifted toward a risk-off move as investors price in continued escalation. Bonds sold off further, reflecting inflation fears in developed markets. Due to the segmented nature of natural gas markets, the impact of higher prices will hit regions differently, with Europe more exposed than the U.S. to elevated LNG prices.   The central question: will this remain a short-term volatility spike or evolve into a broader supply shock? The duration of the disruption and the severity of transit impacts are the core variables I'm watching.   ⬇️ Watch the full video for my latest take on what this could mean for markets.

Something VERY cool just happened in California and… it could be the future of energy.   On July 29, just as the sun was setting, California’s electric grid was reaching peak demand.   However, instead of ramping up fossil fuel resources, the California Independent System Operator (CAISO) and local utilities decided to lean on a network of thousands of home batteries.   More than 100,000 residential battery systems (made up primarily by Sunrun and Tesla customers) delivered about 535 megawatts of power to California’s grid right as demand peaked, visibly reducing net load (as shown in the graphic).   Now, this may not seem like a lot but 535 megawatts is enough to power more than half of the city of San Francisco and that can make all the difference when a grid is under stress.   This is what’s called a Virtual Power Plant or VPP. It’s a network of distributed energy resources that grid operators can call on in an emergency to provide greater resilience to our energy systems. Homeowners are compensated for the dispatch, grid operators are given another tool for reliability, and ratepayers are saved from instability. It’s a win-win-win.   Now, this was just a test to prepare for other need-based dispatches during heat waves in August and September. But it’ historic.   As homeowners add more solar and storage resources, the impact of these dispatch events will become even more profound and even more necessary. This was the second time this summer that VPPs have been dispatched in California and I expect to see even more as this technology improves.   Shout out to Sunrun, Tesla, and all companies who participated. Keep up the great work.

Now out: our latest paper (pre-print) A study on cross-border "cannibalization" of wind and solar energy https://lnkd.in/ebPCdA5m It is now well established theoretically and empirically that the market revenues of wind and solar energy tend to decline as their market share grows. I call this the "market value drop". (Actually, I wrote my very first paper about this: https://lnkd.in/eFtNgpfR) In this paper, we use 2015-23 empirical data in monthly granularity. We see a drop in wind and solar market value (capture rates) in almost all European bidding zones. We are particularly interested in the role of imports and exports as a source of power system flexibility. Many EU bidding zones are *really* well interconnected, with import/export capacity >>100% of their average electricity demand. My favorite results figure shows the impact of domestic wind (dark) and neighbouring wind (light) as a function of my own interconnectedness. If I have no interconnectors, domestic wind depresses market value strongly. Interconnection dampens this effect. However, there is a downside to this: with more interconnectors, the impact of my neighbour's wind on my own value factor becomes stronger. We have tons of more interesting findings. For example: If wind market share increases by 1 pp in Europe, the capture rate drops by about 1.1 pp. This is the combined effect of domestic (0.6) and cross-border (0.5) cannibalization. Many thanks for the great work: Clemens Stiewe, Alice Lixuan Xu, Anselm Eicke! This has been a long haul, but I am pretty proud of how far we got with this! https://lnkd.in/ebPCdA5m

Amid all the economic & geopolitical uncertainty, global energy investment is set to rise this year to $3.3 trillion. China is by far the world's single largest investor in energy, spending almost as much as the US & EU combined. Read more in the International Energy Agency (IEA)’s new report → https://iea.li/4kVvhkF Around $2.2 trillion is set to be invested collectively in renewables, nuclear, grids, storage, low-emissions fuels, efficiency & electrification in 2025. This is twice as much as the $1.1 trillion going to oil, gas & coal. Explore IEA's World Energy Investment → https://iea.li/43FIxCN Global upstream oil investment is set to fall for the 1st time since 2020. The 6% drop is driven mainly by a decline in the US shale sector. By contrast, investment in new LNG facilities is on an upward trajectory, with new projects in the US, Qatar, Canada preparing to start up. Today’s investment trends clearly show a new Age of Electricity is drawing nearer. This year, electricity investments are on course to be some 50% higher than the total amount being spent bringing oil, natural gas and coal to market, accounting for over half all energy investment. In a worrying sign for electricity security, #investment in grids is failing to keep pace with spending on power generation & electrification. Maintaining electricity security requires investment in grids to rise towards parity with power generation spending by the early 2030s. Fierce competition is contributing to falling prices for solar PV & batteries – but electricity equipment costs are going up, with transformers & cables in short supply. Meanwhile, higher US steel & aluminium prices are pushing up costs for drilling & large engineering projects. Rapid growth in electricity demand is underpinning continued investment in coal supply, mainly in China and India. In 2024, China started construction on nearly 100 GW of new coal-fired power plants, pushing global approvals of coal-fired plants to their highest level since 2015. Investment in biofuels, biogases & low-emissions hydrogen is set to rise to a record high in 2025. But projects are facing headwinds given an uncertain policy environment and a number have been cancelled or delayed. Read the IEA's World Energy Investment 2025, freely available in full on our site → https://iea.li/43FIxCN And to learn more, join our Chief Energy Economist Tim Gould, lead report author Cecilia Tam & me for the LIVE launch event from 11:00 CEST → https://iea.li/4jup9yA

In a significant boost to the transition to renewables, AGL has successfully trialled shutting down a coal unit in the middle of the day. This news hasn't been widely reported, but last weekend Unit 2 at the Bayswater coal-fired power station was taken offline around 8am and then brought back online at 3pm. This is a process known as "two-shifting", and it is something AGL first tested about a year ago, following months of pre-testing, simulation training, and detailed planning. Since then, it has been quietly extending the practice through tests on other units. The output of these units is already being dialled down to 20% on a daily basis, and now it is being shut off completely on occasions such as last weekend, when demand was low and solar output was high. The significance of this should not be underestimated. Currently, the main reason wholesale prices go negative in the middle of the day is because coal generators are prepared to bid negative prices to ensure they are dispatched and stay online through the solar peak. And this has ramifications for other generation due to economic curtailment. Wind and solar farms are often forced to shut down because their contracts require them to do so when prices go negative. This has led to more than 90% of large scale solar farms being switched off at times. In theory, if more coal units start going offline in the middle of the day, it will make room for more wind and solar on the grid, as well as incentivising more investment in new projects. It's likely there is a cost to the coal generator of two-shifting, but this may be outweighed by the savings from not continuing to run through periods of negative prices. It effectively enables the coal generators to maximise their market involvement during peak times and avoid low-price periods. Coal in Australia is no longer operating only as inflexible baseload generation — it is adapting into a more flexible role before eventually being retired. #energy #renewables #energytransition

Picture of the Week: European power prices are now lower than pre-Ukrainian times! The significant reduction in #European wholesale power prices in 2024 compared to 2021, especially in countries like #Spain and #Portugal, can be attributed to several key factors: 1. Expansion of Renewable Energy: Spain and Portugal have made substantial investments in #renewable energy, particularly #solar and #wind power. Since the onset of the Ukrainian crisis, these two countries have added nearly 20 GW of solar and wind capacity, which now represents about 15% of their total installed electricity capacity. This massive build-out of renewables has played a crucial role in reducing reliance on fossil fuels and lowering electricity prices. As a result, Spain has seen a dramatic increase in the share of #electricity generated from #renewables, rising from 51% in 2021 to 65% in 2024. This shift has significantly contributed to reducing wholesale power prices by half compared to 2021 levels. 2. Diversification Away from Russian Gas: The European Union, along with individual countries, has made concerted efforts to reduce dependence on #Russian #naturalgas, which was a major factor driving high energy prices during the 2022/2023 period. These efforts included securing alternative gas supplies, increasing LNG imports, and enhancing gas storage capacities. The shift away from Russian gas, coupled with a mild winter and lower overall demand for gas, has eased pressure on gas prices, which in turn has lowered electricity prices across much of Europe. 3. Energy Efficiency Measures: Governments across Europe have implemented #energyefficiency programs aimed at reducing overall energy consumption. These measures, along with public campaigns promoting energy savings, have contributed to reducing electricity demand, helping to stabilize or lower prices. 4. Government and Industry Cooperation: There has been close cooperation between governments and energy companies to stabilize the energy market.

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.

New Frontier Economics study on potential #marketsplitting of electricity bidding zones in Germany. Background: With increasing network congestion and corresponding redispatch cost (2026 forecast: > 6bn €!), the debate about splitting Germany‘s uniform wholesale price zone is heating up. Yesterday Jens Perner presented findings of our study for the Ministerium für Umwelt, Klima und Energiewirtschaft Baden-Württemberg: 🔸 Network extension is key and large North-South connections are scheduled to go online soon (see picture), releasing the pressure on North South network bottlenecks substantially. 🔸 In this context market splitting does not provide clear net benefits: While it improves dispatch efficiency, locational investment signals are unclear, and it negatively impacts on trading liquidity and market power abuse potential. Plus there are significant one-off cost to reconfigure from 1 to 2 or more zones. 🔸 In addition, the expected North-South price delta (~10 €/MWh in 2025, shrinking to €6/MWh in 2030 due to network extensions, though) has substantial distributional effects that may cause further disruptions: Wind offshore investors, for example, have paid billions in auctions to get the right to build unsubsidised wind parks in the North or Baltic Sea based on the expectation of a uniform price zone. They may reconsider whether to actually build if now they can only achieve the lower North zone price, putting our renewable targets at risk. 🔸 In case network extension will not be realised as scheduled this would require a re-assessment of the bidding zone question. Any questions don’t hesitate to contact Jens and the team (Aria Rodgarkia-Dara, Stefan Lorenczik, Julian Bauer and Osama Mahmood).

I'm working on a report about data center developers building their own power plants and this data shocked me: 48 GW of proposed data centers—roughly 33% of all planned capacity—now plan to skip the grid by building "behind-the-meter" projects. This is a very new trend. A little more than a year ago, virtually all data center developers planned to use the electric grid to power 100% of their projects. In December 2024, there was less than 2 GW of planned behind-the-meter data center capacity, according to our data center tracker at Cleanview. Then in 2025, developers announced roughly 40 projects that planned to skip the grid partially or entirely. Some of these projects will soon be home to America's largest fossil fuel power plants, like Homer City Energy Campus in PA—a proposed 4 GW+ natural gas plant that will send all of its power to an onsite data center. Other projects will use a combination of technologies—everything from solar, wind, batteries, and even nuclear. Natural gas is by far the most common, though. 72% of projects plan to use it. All projects are motivated by the same goal: getting their data center online as soon as possible. It can take as long as 7 years to connect a hyperscale data center to the grid in a place like Virginia. Building behind the meter power in a red state with lax regulations can get that time down to less than 2 years. But speed comes with a cost. Homer City's 4 GW project could soon become one of the largest single sources of carbon emissions in the country. At Cleanview we're tracking more than 30 projects that plan to use onsite gas with a combined 48 GW of capacity. I'm planning to write much more about this. In the meantime, I'd love to hear what you'd want to see in the full report. What questions do you have about this new trend?