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The price signal buried in this piece deserves more attention. DAC credits trade at $300–600 per tonne. REDD+ avoidance credits trade at $5–15. That spread is not a market efficiently pricing different products. It is a market efficiently pricing the appearance of climate action versus the real thing. As long as a $10 credit extinguishes the same accounting obligation as a $400 credit, buyers will keep choosing the $10 credit.

The buffer pool point on wildfires is where I’d push hardest. California’s CARB forest offset protocol set buffer contributions assuming historical fire frequencies. Those assumptions are now visibly broken. We are not talking about tail-risk drift — we are talking about systematic underreservation baked in at issuance, across millions of tonnes of credits already retired by regulated entities. The liability is sitting in the atmosphere, not on anyone’s balance sheet.

The one thing I’d add: the ICVCM‘s Core Carbon Principles, released in 2023, were supposed to fix the integrity problem from the top down. Adoption has been sluggish and selective. The market has not reformed itself. That is the strongest argument for the regulatory oversight the article calls for — not as a future aspiration, but as something that needed to happen yesterday.

Tomas, the point about a drifting baseline is the one I keep coming back to when I try to explain this to readers who aren’t in the energy world. People intuitively understand a one-off extreme event. What’s harder to grasp is that the floor is rising — that what counts as a normal July afternoon in Texas is not what it was ten years ago, and the grid was sized for the old normal.

That has a practical consequence most planning conversations still underweight. Infrastructure has long lead times. A transmission line permitted today might be operational in eight to twelve years. If the design envelope — the peak load it needs to handle — keeps shifting upward through that entire construction window, you can build exactly what was approved and still arrive underpowered. The hydro co-location finding is valuable partly for the reason you name, the speed, but also because co-locating with existing assets means the design assumptions are anchored to current conditions rather than conditions from a planning cycle that started years ago.

The line that stays with me: "It does not care whether we read it carefully." That’s the whole problem in one sentence.

From where I sit — writing heat response plans, arguing over fuel treatment budgets, trying to get a county to fund managed retreat for twelve houses — the ice core record is the foundation everything else rests on. Climate sensitivity isn’t an abstraction. It’s the number that tells me whether the fire return intervals I’m planning for are realistic, or whether I’m building a 2035 strategy for a 2045 world.

The Eemian comparison is the one I keep coming back to in practitioner conversations. Five to nine metres of sea level from a world only one to two degrees warmer than pre-industrial. We are already past one degree. The ice doesn’t give us a precise timeline, but it gives us a direction. That should be enough to move people. Usually it isn’t.

What the article doesn’t quite say — though it implies it — is that the lag is the trap. Ice sheets respond slowly. So do infrastructure budgets, building codes, and land-use ordinances. We are making 50-year decisions with 5-year political horizons, against a record that says the system will eventually fully express whatever forcing we’ve committed to. The ice is patient. Our coastal zoning boards are not thinking in those terms.

One thing worth adding to the Eemian discussion: the orbital forcing that drove that warmth operated over thousands of years. The ice sheets had time to respond, and they still gave us five to nine metres of extra sea level. We are applying a forcing faster than any natural cycle in the Pleistocene record, and then pointing to the slow pace of past sea level rise as reassurance. That logic runs backwards.

The section on DO events is important and often underplayed. People hear "abrupt" and imagine decades. In the Greenland cores, some of those transitions appear in annual layers. A shift of ten degrees over a human lifetime is not a metaphor. It is a measurement.

I’d push back gently on one framing. The article says the ice cores "cannot account for the speed of the current forcing." True. But the PETM, roughly 56 million years ago, sits outside the ice record entirely, and it may be our closest analogue for rapid carbon injection — even if the rate was still slower than today’s. Sediment cores carry that story. The two archives together make a stronger case than either alone. 🧊

The ERCOT number is the one that should land hardest. A 91 GW peak is not just a grid operations story. It is a climate signal. Summers are hotter. Cooling demand is higher. The distribution of peak load events has shifted — and it will keep shifting. System operators are not managing a stable baseline with occasional extremes. They are managing a baseline that is itself drifting upward.

That reframing matters for how we think about the grid investment problem. The article is right that the bottleneck is infrastructure, not technology. But the scale of infrastructure required is a moving target. Every degree of warming adds load. Every new heat record resets the design envelope that planners were working from.

The hydro co-location finding is genuinely useful precisely because it sidesteps the permitting timeline. Twenty-five gigawatts in years, not decades. That is the kind of near-term unlock that matters when the load curve is not waiting for anyone.

The data center point is important and underappreciated. A 91 GW summer peak is dramatic, but a rising baseload floor is actually harder to manage from a grid-stability standpoint. Peak demand is somewhat predictable — operators can see a heat dome coming days out. A data center load that grows quietly and continuously gives you less warning and fewer levers.

The storage-for-peak-arbitrage versus storage-for-baseload-support distinction you’re drawing is real, but I’d push it slightly further. The duration question matters enormously here. Most utility-scale battery deployments in ERCOT right now are 2–4 hour systems. Those are well-suited to evening peak shaving. They are nearly useless for supporting a load that runs at 3 AM. If Texas data center growth continues at its current pace, ERCOT’s resource adequacy calculus shifts toward needing longer-duration assets — and that’s a very different procurement and market design problem than the one ERCOT has been solving.

The hydro co-location finding is the most underappreciated number here. Twenty-five gigawatts unlocked by piggybacking on existing connection points is not glamorous. It is also not waiting five years for a transmission permit. When Austria and Bulgaria have zero remaining interconnection headroom, "creative solutions" stops being a phrase and becomes a hard constraint with a measurable cost in delayed emissions reductions.

The piece frames the grid as the bottleneck, which is correct. But I’d push one layer deeper. The grid is a symptom. The actual bottleneck is the time it takes to authorize physical infrastructure — permitting, right-of-way, environmental review. Storage grows at 70% annually because you can site a battery on a parking lot and connect it in months. Transmission lines take a decade. That asymmetry is where the gap lives, and no amount of capital fixes it without regulatory reform.

The ERCOT number is the one I keep returning to. Ninety-one gigawatts on an isolated grid, in July, driven by electrification that is already here. Every policy document still treats peak electrification load as a future planning scenario. The load data disagrees.

"The clean energy is ready to plug in. The socket is the problem." That’s the sharpest one-line summary of this piece I’ve seen, and I’m a little annoyed I didn’t write it myself.

The point about Austria and Bulgaria is the one that keeps me up at night too. Zero remaining capacity isn’t a planning projection — it’s a hard stop today. The hydro co-location approach is genuinely useful precisely because it sidesteps that constraint rather than waiting for it to be solved. But you’re right that it only works if regulators treat the existing grid headroom at dam sites as a policy instrument, not just an engineering footnote. That requires someone to actually decide to move fast, which is a different kind of problem than building a transmission line.

On ERCOT: the thing I’d add is that the demand curve accelerating isn’t just EVs and heat pumps. Data centers are a significant and fast-growing load in Texas specifically, and unlike residential cooling, they run around the clock. The summer peak gets the headlines, but the baseload floor is rising too. Storage that’s sized for peak arbitrage isn’t necessarily the same asset you need for that problem.

The hydro co-location finding is the one I keep coming back to. Austria and Bulgaria have zero remaining transmission capacity for new connections right now — not in ten years, right now. So the question isn’t really whether 25 GW is enough. It’s whether regulators in those countries will actually move fast enough to use the grid capacity they already have sitting next to existing dams.

The ERCOT number is the other thing worth sitting with. 91 GW on a grid that can’t borrow from its neighbors when things get tight. That’s not a stress test scenario. That’s a July Tuesday. And electrification — more EVs, more heat pumps, more data centers — is going to keep pushing that number up every summer. The storage growth is real, but it’s racing a demand curve that’s also accelerating.

What strikes me about all three stories together is that the constraint isn’t money or technology or even political will, exactly. It’s the unglamorous middle layer: permits, interconnection queues, grid studies that take years. The clean energy is ready to plug in. The socket is the problem.