Direct Air Capture in Europe - Where to Integrate, Where to Store, and What Drives Cost?

Felix M\"usgens; Maximilian Bernecker

arxiv: 2604.05990 · v1 · submitted 2026-04-07 · ⚛️ physics.soc-ph · econ.GN· q-fin.EC

Direct Air Capture in Europe - Where to Integrate, Where to Store, and What Drives Cost?

Maximilian Bernecker , Felix M\"usgens This is my paper

Pith reviewed 2026-05-10 18:24 UTC · model grok-4.3

classification ⚛️ physics.soc-ph econ.GNq-fin.EC

keywords direct air captureCO2 storageenergy system modelingEurope decarbonizationNorth Sea storageelectricity integrationcarbon transport2050 scenarios

0 comments

The pith

Limiting CO2 storage to North Sea sites raises direct air capture costs by about 10 percent, while treating capture as a stand-alone system rather than grid-integrated raises them by up to 30 percent.

A machine-rendered reading of the paper's core claim, the machinery that carries it, and where it could break.

The paper builds a European capacity expansion model that jointly optimizes electricity generation, direct air capture operation, CO2 transport pipelines, and storage for a fully decarbonized 2050 grid. It tests two practical choices: whether storage is confined to offshore North Sea sites or spread across suitable European locations including onshore, and whether capture plants run in isolation or draw on and feed into the electricity system. If these modeled cost differences hold, they imply that current stand-alone cost estimates for direct air capture overstate the expense of using it to offset hard-to-abate emissions. Planners would therefore need to weigh storage access and grid flexibility when deciding where and how to deploy the technology at scale.

Core claim

The authors separate direct air capture, transport, and storage and embed them in a European capacity expansion model for a 2050 decarbonized electricity system. Restricting storage to North Sea depleted gas fields increases overall capture costs by approximately 10 percent compared with allowing distributed sites across Europe. Treating capture facilities as isolated units, rather than allowing them to operate flexibly with the grid or adding them retrospectively to an existing optimized system, increases costs by up to 30 percent.

What carries the argument

A capacity expansion model that optimizes electricity supply, direct air capture electricity use and timing, CO2 pipeline routing, and storage site selection together across Europe.

If this is right

Distributed storage access across Europe avoids a 10 percent cost adder that appears when all captured CO2 must travel to the North Sea.
Allowing capture plants to adjust operation with renewable electricity availability cuts costs by up to 30 percent versus running them independently.
Retrospective addition of capture to an already-optimized grid still captures most integration benefits, reducing the penalty of late-stage deployment.
Electricity cost assumptions dominate total DACCS expenses, so changes in renewable build-out directly scale the viability of capture.

Where Pith is reading between the lines

These are editorial extensions of the paper, not claims the author makes directly.

Policy support for onshore storage permitting could lower overall mitigation costs more than technology subsidies alone.
The same integration logic may apply to other flexible loads such as hydrogen production or industrial electrification.
Extending the model to 2030 or 2040 pathways would show whether early deployment of capture requires even greater emphasis on storage siting.
Real-world pipeline and storage constraints not captured in the optimization could narrow the reported cost gaps.

Load-bearing premise

The model assumes Europe's electricity system reaches full decarbonization by 2050 and that the optimization accurately reflects all integration benefits without missing real-world limits on siting, permitting, or operations.

What would settle it

A measured cost comparison from an actual large-scale direct air capture project in Europe that shows total system costs differing by far less or far more than the modeled 10 percent storage penalty or 30 percent integration penalty.

read the original abstract

Direct Air Carbon Capture and Storage (DACCS) can mitigate hard-to-abate emissions, e.g. from transport or industry. However, there is a wide variety of cost estimates for DACCS, driven, to a significant extent, by differences in electricity cost. At the same time, there is a notable gap in research that integrates direct air capturing systems into long-term energy system models. We separate direct air capturing, carbon transport, and carbon storage and integrate them into a European capacity expansion model for a fully decarbonised electricity system in 2050. We explore how two dimensions affect the total system costs of DACCS. The first dimension is the availability of CO2 storage locations: In one analysis, storage locations are restricted to offshore storage locations in the North Sea only, i.e. depleted natural gas fields. The alternative analysis comprises suitable storage locations distributed across Europe, including onshore. We find that limiting CO2 storage to North Sea sites increases overall capture costs by approximately 10 %. The second dimension is whether DACCS is analysed as stand-alone or integrated into the electricity system. We differentiate between three alternatives: fully isolated, fully integrated, and retrospectively added to an existing system. We find that neglecting system integration - i.e. treating direct air capture system as a stand-alone technology - increases capture costs by up to 30 %.

Editorial analysis

A structured set of objections, weighed in public.

Desk editor's note, referee report, simulated authors' rebuttal, and a circularity audit. Tearing a paper down is the easy half of reading it; the pith above is the substance, this is the friction.

Desk Editor's Note private letter to a colleague

The paper runs a European capacity expansion model to 2050 and reports that North Sea-only storage raises DACCS costs by about 10% while treating the plants as stand-alone raises them by up to 30%.

read the letter

The main things to know are the two quantified cost deltas and the fact that they come from embedding DAC, transport, and storage inside an existing European electricity system model rather than from a new method or dataset. The work separates the capture, transport, and storage pieces and tests two scenario axes: storage geography (North Sea offshore only versus sites across Europe) and degree of system coupling (isolated, integrated, or added after the fact). Those runs produce the 10% and 30% figures that are the paper's concrete outputs. The approach itself follows standard capacity-expansion practice, so the contribution is the specific application and the resulting numbers for a decarbonized 2050 European grid. That is useful for anyone who needs order-of-magnitude estimates on where DACCS might sit in the system and how much integration matters. The model assumptions are stated clearly enough in the abstract to understand the direction of the results. The soft spots are the missing documentation on data sources, model resolution, validation steps, and sensitivity checks. Without those, it is hard to tell how much the reported percentages depend on perfect foresight, unlimited transmission, or the assumption of a fully decarbonized power system by 2050. Real-world permitting delays for onshore storage or inflexible DAC operation could change the deltas, but the paper does not show tests for that. This is for energy-system modelers and European climate-policy analysts who already work with capacity-expansion tools. A reader in that group can extract the scenario results quickly and decide whether the 10-30% range is worth using as a rough bound. It deserves peer review because the topic is relevant, the modeling is straightforward, and referees can require the missing method details without changing the core exercise. Send it on.

Referee Report

2 major / 2 minor

Summary. The paper integrates modules for direct air capture (DAC), CO2 transport, and storage into a European capacity-expansion model of a fully decarbonized 2050 electricity system. It examines two storage-availability scenarios (North Sea offshore sites only versus Europe-wide onshore and offshore) and three integration modes (stand-alone/isolated, fully integrated, and retrospectively added to an existing system). The central quantitative claims are that restricting storage to North Sea sites raises overall DACCS costs by approximately 10 % and that treating DAC as a stand-alone technology (neglecting integration) raises costs by up to 30 %.

Significance. If the underlying capacity-expansion model and its 2050 assumptions are robust, the work usefully quantifies two under-studied cost drivers for DACCS—storage geography and electricity-system integration—thereby filling a noted gap between stand-alone DAC cost studies and full energy-system modeling. The modular separation of capture, transport, and storage is a modeling strength that allows clear attribution of the reported deltas.

major comments (2)

[Methods] Methods / model description: The headline 10 % and 30 % cost deltas are generated inside a capacity-expansion model that assumes a fully decarbonized 2050 European electricity system with perfect foresight and no unmodeled transmission or permitting constraints. No sensitivity runs, validation against historical data, or comparison to other European models are reported; because these assumptions directly determine the integration benefits that produce the 30 % figure, they are load-bearing for the central claims.
[Results] Results section on storage scenarios: The 10 % cost increase for North-Sea-only storage is presented as a robust finding, yet the paper provides no breakdown of how storage capacities, injection rates, or transport distances were parameterized, nor any test of whether onshore storage availability assumptions are consistent with current regulatory and geological data.

minor comments (2)

[Abstract] Abstract and introduction: The three integration alternatives (fully isolated, fully integrated, retrospectively added) are introduced without a concise table or diagram that maps each to the corresponding model runs; this makes it difficult to trace which scenario produces the “up to 30 %” upper bound.
[Methods] Notation: Electricity cost profiles and storage site costs are listed as free parameters but are not accompanied by explicit ranges or sources in the main text; a supplementary table would improve reproducibility.

Simulated Author's Rebuttal

2 responses · 0 unresolved

We thank the referee for the constructive comments and for recognizing the value of quantifying storage geography and electricity-system integration effects on DACCS costs. We address each major comment below, providing clarifications on our modeling approach and indicating the revisions we will implement to improve transparency and robustness.

read point-by-point responses

Referee: [Methods] Methods / model description: The headline 10 % and 30 % cost deltas are generated inside a capacity-expansion model that assumes a fully decarbonized 2050 European electricity system with perfect foresight and no unmodeled transmission or permitting constraints. No sensitivity runs, validation against historical data, or comparison to other European models are reported; because these assumptions directly determine the integration benefits that produce the 30 % figure, they are load-bearing for the central claims.

Authors: We agree that the model's assumptions are central to the integration benefits. The capacity-expansion framework uses perfect foresight as a standard feature for identifying least-cost pathways to 2050 decarbonization targets, consistent with the PyPSA-Eur model lineage and other European studies. Transmission is represented at the zonal level with existing and planned lines, though finer-grained constraints are not fully resolved. We acknowledge that the original submission lacked explicit sensitivity testing on these elements. In the revised manuscript we will add a dedicated subsection on model assumptions and limitations, explicitly discussing perfect foresight, transmission representation, and permitting as a noted uncertainty. We will also include new sensitivity runs varying renewable cost assumptions and electricity demand to quantify impacts on the 30 % delta, plus a brief comparison of key cost outputs to recent multi-model studies such as those from the European Commission. revision: partial
Referee: [Results] Results section on storage scenarios: The 10 % cost increase for North-Sea-only storage is presented as a robust finding, yet the paper provides no breakdown of how storage capacities, injection rates, or transport distances were parameterized, nor any test of whether onshore storage availability assumptions are consistent with current regulatory and geological data.

Authors: We accept that additional parameterization detail is required for transparency. The storage module draws capacities from publicly available geological assessments (total European potential and North Sea subset), injection rates from literature values for depleted reservoirs, and transport costs via an embedded pipeline network. In the revised manuscript we will expand the Methods section with a table and accompanying text providing: explicit storage capacity figures and sources, assumed injection rates per site with references, and average transport distances under each scenario. We will further add a sensitivity case that restricts onshore storage to sites with documented regulatory progress or lower conflict, thereby testing the robustness of the 10 % result against current geological and policy data. revision: yes

Circularity Check

0 steps flagged

No significant circularity; cost deltas are direct outputs of forward scenario simulations

full rationale

The paper embeds DAC, transport and storage modules inside a European capacity-expansion model and reports cost differences from explicit scenario comparisons (North Sea-only storage vs. Europe-wide; stand-alone vs. integrated operation). These percentages are produced by running the model under alternative constraints and subtracting the resulting objective values; no parameters are fitted to the target deltas, no self-definitional equations equate inputs to outputs, and no load-bearing self-citations are invoked to justify the central claims. The derivation chain therefore remains self-contained as standard scenario analysis without reduction to tautology.

Axiom & Free-Parameter Ledger

2 free parameters · 2 axioms · 0 invented entities

The analysis rests on standard energy system modeling assumptions and cost parameters typical in the field, which are not detailed in the abstract but are common in capacity expansion studies.

free parameters (2)

Electricity cost profiles
Vary by integration scenario and drive the 30% cost difference
CO2 storage site costs and capacities
Differ between North Sea only and Europe-wide cases

axioms (2)

domain assumption European electricity system is fully decarbonized by 2050
Explicitly stated as the modeling context for the capacity expansion
domain assumption Capacity expansion model captures all relevant system interactions for DACCS
Core premise enabling the integration vs stand-alone comparison

pith-pipeline@v0.9.0 · 5552 in / 1296 out tokens · 58053 ms · 2026-05-10T18:24:47.032873+00:00 · methodology

discussion (0)

Reference graph

Works this paper leans on

2 extracted references · 2 canonical work pages

[1]

Table 6: Information storage sites Nr. Annual CAPEX EUR/tCO2 FIX O&M costs EUR/tCO2 Var O&M costs EUR/tCO2 Energy Demand in kWh/tCO2 Max Stor in Mt/y Project, PCI number/ source 1 3.18 1.88 7.05 13.88 5 CO2TransPorts 13,1 2 3.18 1.88 7.05 13.88 22 Aramis 13,2 3 3.18 1.88 7.05 13.88 10.5 Bifrost 13,4 4 3.18 1.88 7.05 13.88 20 EU2NSEA - Smeaheia 13,8 4 3.18...

work page 2025
[2]

and one connected to a smaller storage site of 1.1 Mt CO2/year in Ireland (Nr. 37). Comparing the Integrated scenarios depicted in the third row of Figure 2 with the previous Added scenarios shows that overall, the system configurations are almost the same, with only minor differences in installed storage and direct air capture systems capacities. The rea...

work page 2041

[1] [1]

Table 6: Information storage sites Nr. Annual CAPEX EUR/tCO2 FIX O&M costs EUR/tCO2 Var O&M costs EUR/tCO2 Energy Demand in kWh/tCO2 Max Stor in Mt/y Project, PCI number/ source 1 3.18 1.88 7.05 13.88 5 CO2TransPorts 13,1 2 3.18 1.88 7.05 13.88 22 Aramis 13,2 3 3.18 1.88 7.05 13.88 10.5 Bifrost 13,4 4 3.18 1.88 7.05 13.88 20 EU2NSEA - Smeaheia 13,8 4 3.18...

work page 2025

[2] [2]

and one connected to a smaller storage site of 1.1 Mt CO2/year in Ireland (Nr. 37). Comparing the Integrated scenarios depicted in the third row of Figure 2 with the previous Added scenarios shows that overall, the system configurations are almost the same, with only minor differences in installed storage and direct air capture systems capacities. The rea...

work page 2041