u/raw-science

Sunlight is renewable. Wind is renewable. A solar panel is not, or at least not yet. It's silicon refined at 1500–2000°C in carbothermic arc furnaces, silver paste screen-printed onto a cell, aluminum smelted in Hall-Héroult cells, EVA encapsulant cracked out of naphtha, tempered glass melted in natural gas furnaces at more than 1000°C. That said, roughly 75% of the world's polysilicon is made in China, where about 60% of the grid is still coal. So when one reads "25–50 g CO₂eq/kWh" for utility-scale PV, that number is conditional on the manufacturing mix. If the mix decarbonizes, the number drops. If it doesn't, the fossil substrate stays embedded in every panel.

I’m not making the bad faith argument that “but renewable energy sources emit too!”, indeed, PV's carbon payback is genuinely only 1–4 years against a 25–30 year lifetime. And coal is 820–1000 g/kWh in equivalent LCAs.

What I think gets lost many times is that the energy transition isn't really a substitution of generation sources, but likely a reconfiguration of the industrial base that builds the generation sources. And that base, i.e., steel, cement, petrochemicals, aluminum, refined copper, is still roughly 35-40% of global energy-related emissions today.

Take the cement as an example. About 65% of cement’s direct CO2 emissions come from the calcination reaction itself, not from fuel combustion, so even fully decarbonized heat does not eliminate most of its process emissions. Offshore wind, transmission, batteries, and solar all depend on steel, cement, aluminum, copper, and other materials whose production remains emissions-intensive today.

That is also why supply-chain constraints matter. The IEA’s net-zero pathways require a major scale-up in solar PV and wind, and mineral demand for clean energy technologies rises sharply, with lithium, graphite, nickel, cobalt, and copper all facing strong growth and potential bottlenecks.

Don´t take these arguments against the energy transition; I think electrification is necessary. But the honest framing is that electrification doesn't end our resource dependence; it restructures it. It trades a flow problem (burning fossil fuel) for a stock problem (mining and refining vast quantities of metals once, then hopefully recycling them well). Those are different problems with different politics, different geographies, and different bottlenecks. Pretending it's just "clean vs dirty" makes the policy worse.

I wrote a longer piece (for now in Spanish) working through the material chain, the LCA boundary problem, and the supply-gap numbers with citations. If anyone wants the deeper version, check raw-science. org

I was going through the history of long-duration energy storage (LDES) systems and I was quite impressed by their evolution. Vanadium redox flow batteries (VRFB) were licensed and pushed toward commercialization in the mid 90s. For the Sodium-ion batteries, the research started in parallel with lithium-ion in the 70s, with the NASA and the national labs involved early. The Iron-air technologies show also roughly five decades of investigations. And in every cycle the public framing has been some kind version of "five years away from being competitive."

The last 18 months have been, in my opinion, pretty brutal for the sector. Natron Energy collapsed in September 2025 after failing to raise more capital, and abandoned their gigafactory plans. ESS Tech (iron flow tech) has issued formal "going concern" warnings about its ability to continue operating. Eos Energy has accumulated something like $1.9B in net losses. Invinity still hasn't reached an operating profitability. Redflow (zinc-bromo chemistry) went under at the end of 2024. Meanwhile the VRFB deployment finally crossed 1 GWh globally last year... even though almost entirely from one Chinese project (the Jimusar, 200 MW / 1 GWh). Outside China, the cumulative deployed capacity is still measured in low hundreds of MWh.

But I honestly think there are at least two reasons the pattern might be breaking.

One in more empyrical: the learning curve for lithium-ion batteries resulted in a 20–27% reduction in costs for every twofold increase in the cumulative capacity between 1990 and 2020. That's faster than almost anyone predicted in the 2000s. There's no obvious physical reason LDES chemistries with comparable manufacturing characteristics couldn't follow similar curves once they reach production volume. The second is more policy-related: specific revenue mechanisms for long-duration energy are finally being established. The UK’s Ofgem cap-and-floor system explicitly allows for vanadium flow systems. California, Italy, and Australia are holding auctions for LDES systems. And Form Energy has signed agreements with utilities and data centers. None of this existed in previous cycles.

What I'm not sure about is whether these mechanisms move enough volume and fast enough, or whether they just keep a few survivors alive long enough for the next industry-wide crisis. The Sepulveda et al. modeling in Nature Energy suggests LDES needs to hit less than $20/kWh to meaningfully reduce the total system cost, and reach $1/kWh to fully replace firm low-carbon generation... a number the authors themselves call "unlikely with known technologies."

Full analysis with refs at raw-science. org (in spanish).

I was going through the history of long-duration energy storage (LDES) systems and I was quite impressed by their evolution. Vanadium redox flow batteries (VRFB) were licensed and pushed toward commercialization in the mid 90s. For the Sodium-ion batteries, the research started in parallel with lithium-ion in the 70s, with the NASA and the national labs involved early. The Iron-air technologies show also roughly five decades of investigations. And in every cycle the public framing has been some kind version of "five years away from being competitive."

The last 18 months have been, in my opinion, pretty brutal for the sector. Natron Energy collapsed in September 2025 after failing to raise more capital, and abandoned their gigafactory plans. ESS Tech (iron flow tech) has issued formal "going concern" warnings about its ability to continue operating. Eos Energy has accumulated something like $1.9B in net losses. Invinity still hasn't reached an operating profitability. Redflow (zinc-bromo chemistry) went under at the end of 2024. Meanwhile the VRFB deployment finally crossed 1 GWh globally last year... even though almost entirely from one Chinese project (the Jimusar, 200 MW / 1 GWh). Outside China, the cumulative deployed capacity is still measured in low hundreds of MWh.

But I honestly think there are at least two reasons the pattern might be breaking.

One in more empyrical: the learning curve for lithium-ion batteries resulted in a 20–27% reduction in costs for every twofold increase in the cumulative capacity between 1990 and 2020. That's faster than almost anyone predicted in the 2000s. There's no obvious physical reason LDES chemistries with comparable manufacturing characteristics couldn't follow similar curves once they reach production volume. The second is more policy-related: specific revenue mechanisms for long-duration energy are finally being established. The UK’s Ofgem cap-and-floor system explicitly allows for vanadium flow systems. California, Italy, and Australia are holding auctions for LDES systems. And Form Energy has signed agreements with utilities and data centers. None of this existed in previous cycles.

What I'm not sure about is whether these mechanisms move enough volume and fast enough, or whether they just keep a few survivors alive long enough for the next industry-wide crisis. The Sepulveda et al. modeling in Nature Energy suggests LDES needs to hit less than $20/kWh to meaningfully reduce the total system cost, and reach $1/kWh to fully replace firm low-carbon generation... a number the authors themselves call "unlikely with known technologies."

Full analysis with refs at raw-science.org.

How much does electricity cost? It seems like a simple question, but in practice it actually involves at least four different questions, and the answer you get depends entirely on which one you’re really asking. Every couple of months you hear: "renewables now produce the cheapest electricity in history." And then, often the same week, the opposite one: "renewables are driving up European electricity costs." Both can actually cite real reports. Both can be technically correct. And both can be misleading, because they're quietly answering different questions.

I’ve been working on a more detailed analysis of this topic, but I wanted to share the basic framework here, since it explains many of the “contradictions” that come up in energy debates.

Most of the confusion comes from mixing up four different metrics that measure very different things: LCOE, System LCOE, VALCOE, and LCOLC. Here are some details about the four of them.

1.- LCOE (Levelized Cost of Electricity) is by far the most cited metric in public debate, policy briefs, news coverage, and industry presentations. It answers a specific question: what does it cost, on average, to generate 1 MWh in a given plant over its lifetime, accounting for CAPEX, O&M, fuel where relevant, and a discount rate tied to the cost of capital. Fraunhofer ISE publishes one of the most widely cited European reference series. Their 2024 study, which focuses on the German energy system, provides a useful overview of the distribution: utility-scale PV around 41–69 €/MWh, onshore wind around 43–82 €/MWh, offshore wind around 73–123 €/MWh, and other low carbon technologies in the 137–289 €/MWh range, heavily dependent on capital cost assumptions. Under this metric, solar and onshore wind are genuinely the cheapest options available. It is important to note that the LCOE refers to a single power plant, not an entire system. Treating it as "the cost of the grid" is closer to quoting the cost of building one car as the cost of running a 24/7 taxi network.

2.- System LCOE includes the integration costs that arise when intermittent energy generation is incorporated into an established grid: balancing, the temporal mismatch between production and demand (profile cost), grid reinforcement, curtailment, and the structural reality that firm capacity still has to exist for windless winter evenings, but that would run fewer hours and recovers its fixed costs over fewer MWh. What is most often overlooked in the headlines is that these costs grow non-linearly as renewable penetration increases. At 10–20% variable renewable share, the integration costs are modest and the existing grid absorbs them with relatively little structural changes. In this range, the renewable integration is often net beneficial: renewables displace higher marginal-cost generation, reduce fuel consumption, and can even improve price dynamics without yet imposing significant system-level penalties. At around 30–40%, the curve begins to rise significantly and the system shifts in regime: profile effects and firm-capacity requirements are no longer secondary considerations and bacome the dominant cost drivers. Thus, increasing the share of renewable energy from 15% to 70% is not five times more difficult; rather, it involves a different operating framework, in which renewable energy shifts from being an add-on to a dispatchable system to becoming the backbone around which the rest of the system must be redesigned.

3.- VALCOE (Value-Adjusted LCOE), developed by the Internation Energy Agency (IEA), asks what is a MWh actually worth when it hits the market. A solar plant producing mostly at midday, when wholesale prices are depressed because every other solar plant is also producing, captures a lower average price than the annual mean. By contrast, a firm plant that can operate during scarcity hours captures a higher price. As solar and wind penetration grows, this capture price deflates structurally. The physical output (MWh) is the same, but its economic value is not. In the IEA’s modeled EU 2050 scenarios, this effect becomes large enough that the value-adjusted cost of solar can exceed, and in some cases more than double, its LCOE value.

4.- LCOLC (Levelized Cost of Load Coverage) addresses the hardest question of the four: what does it cost to actually meet demand, hour by hour, across the year? I show here an example: an industrial site needs a constant 1 kW of power. Over a full year, that equals 8,760 kWh of electricity demand and if the site tried to cover that demand with solar alone in Europe, where solar typically delivers around 1,100 full-load equivalent hours per year, it would need roughly 8 kW of installed PV capacity just to generate the same annual amount of energy. But even that is not enough. The energy may balance on paper, but the load does not. Solar produces at midday, less in winter, and nothing at night. So the real system also needs storage, backup capacity, or both. This is where LCOLC becomes useful. It asks not what one MWh costs when produced, but what the full system costs when demand must actually be covered. A recent German study by Grimm, Oechsle & Zöttl (2024) illustrates the point clearly: even with projected 2040 PV LCOE of around 45 €/MWh, covering load with solar and batteries alone rises above 200 €/MWh. A mixed system of wind, solar, batteries and hydrogen reduces that cost to around 78 €/MWh. Adding gas backup can lower it further, though the result becomes highly sensitive to the carbon price.

My purpouse is not to argue for or against any particular technology. It's more to be precise about what we're measuring when we discuss electricity costs. The difference between 25 €/MWh and 80 €/MWh in the same system is not a rounding error or a methodological issue: it reflects the difference between producing energy and guaranteeing supply. Both are legitimate things to measure, and both belong in the conversation, but they are not interchangeable. My impression from following European debates is that LCOE continues to dominate the political conversation while system operators are increasingly working in System LCOE and LCOLC territory.

The full analysis (in Spanish) with data from Fraunhofer ISE, Ueckerdt et al., the IEA, and the Grimm et al. policy brief at raw-science.org.