Tag: hydrogen

The key difference between an alkaline electrolyser and a proton exchange membrane electrolyser (PEM) is what ion diffuses between the anode and cathode side of the cell. In an alkaline electrolyser, alkaline OH- ions diffuse. In a PEM electrolyser, protons, H+ ions, diffuse. Ten fundamental differences follow.

The lowest cost green hydrogen will come from alkaline electrolysers run at high utilizations, powered by clean, stable grids with excess power (e.g., nuclear, hydro).

PEMFCs are more suited for backstopping renewables, although there is still some debate over the costs, longevity, efficiency and whether intermittent wind/solar can be put to better use elsewhere.

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(1) In an alkaline electrolyser, water is broken down at the cathode. 4 x H2O molecules gains 4 x e- and become 2 x H2 + 4 x OH- ions. The OH- ions then diffuse across the cell to the anode. To complete the electrical circuit, 4 x OH- ion surrender 4 x e- at the cathode and become 2 x H2O molecules + 1 x O2 molecule. A schematic is below.

(2) In a PEM electrolyser, the chemistry is very different. Water is broken down at the anode. 2 x H2O molecules surrender 4 x e- and become an O2 molecule + 4 H+ ions (protons). The H+ ions then diffuse across the cell to the cathode. To complete the electrical circuit, at the cathode, 4 x H+ ions gain 4 x e- and become 2 x H2 molecules.

(3) PEMs have Membranes. H+ ions are the smallest ions in the Universe, measuring 0.0008 pico-meters (comparable with other ionic radiuses below). This means protons can diffuse through solid polymers like Nafion, which otherwise resist electricity and resist the flow of almost all other materials; totally isolating the anode and cathode sides of the cell in a PEMFC.

Ionic radius: comparing cation chemistry?

(4) Alkaline Electrolysers have Diaphragms. OH- ions are larger, at 153 pm (which is actually quite large, per the chart above). Thus they will not diffuse through a solid polymer membrane. Consequently, the anode and cathode are separated by a porous diaphragm, bathed in an electrolyte solution of potassium hydroxide, produced via a variant of the chlor-alkali process. This (alkaline) electrolyte also contains OH- ions. This helps, because more OH- ions makes it faster for excess OH- ions to diffuse from high concentration on the cathode side of the cell to low concentration on the anode side of the cell (see (2)).

Chlor-alkali process: the economics?

(5) Safety implications. Alkaline electrolysers are said to be less safe than PEMs. The reason is the porous diaphragm. Instead of bubbling out as a gas on the anode side, very small amounts of oxygen may dissolve, diffuse ‘in the wrong direction’ across the porous diaphragm, and bubble out alongside the hydrogen gas at the cathode side. This is bad. H2 + O2 make an explosive mixture.

(6) Footprint implications. One way to deal with the safety issue above is to place the anode and cathode ‘further apart’ for an alkaline electrolyser. This lowers the chances of oxygen diffusing across the diaphragm. But it also means that alkaline electrolysers are less power-dense.

(7) Efficiency implications. Small amount of current can leak through the KOH solution in an alkaline electrolyser, especially at very large current densities. When a direct current (e-) is added to the cell, we want it to reduce 2 x H+ into H2. However, a small amount of the current may be wasted, converting K+ into K; and a small amount of ‘shunt current’ may flow through the KOH solution directly from cathode to anode. We think real-world PEMs will be around 65% efficient (chart below, write-up here) and alkaline electrolysers will be multiple percentage points lower.

(8) Cost implications. An alkaline electrolyser may be a few $100/kW cheaper than a PEM electrolyser. Because the diaphragm is cheaper than the membrane. The electrodes are cheaper too. Our overview of electrolyser costs is below.

Electrolysers: how much deflation ahead for hydrogen?

(9) Longevity implications. Today’s PEMs degrade 2x faster than alkaline electrolysers (40,000 hours versus 90,000 hours, as general rules of thumb). This is primarily because the membranes are fragile. And H+ ions are, by definition, acidic. But as with all power-electronics, the rate of degradation is also a function of the input signal and operating conditions.

Battery degradation: causes, effects & implications?

(10) Flexibility implications. Alkaline electrolysers are not seen to be a good fit for backstopping renewables (chart above). According to one technical paper, “It is well known that alkaline water electrolysers must be operated with a so-called protective current in stand-by/idle conditions (i.e., when no power is provided by renewable energy sources) in order to avoid a substantial performance degradation”. When ion flow stops, there is nothing driving OH- ions across the cell, and pushing the H2 and O2 out of the cell. In turn, this means O2 and H2 bubbles can form. They may accumulate around electrode catalysts. Then when the cell starts up again, the gas bubbles block current flow. In turn, overly large resistance or current densities can then degrade the catalysts.

Green hydrogen: can electrolysers run off renewables?

Our mission is to find economic opportunities that can drive the energy transition, substantiated by transparent data and modelling. Therefore, we have looked extensively for opportunities in hydrogen, but somewhat failed to find very many.

More pessimistically stated, we fear that the ‘green hydrogen economy’ may fail to be green, fail to deliver hydrogen, and fail to be economical. We see greater opportunities elsewhere in the energy transition.

This short note summarizes half-a-dozen deep-dive research notes, plus over a dozen models and data-files into the commercialization of hydrogen. There may be opportunities in the space, but they must be chosen very carefully.

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An overview of different hydrogen pathways?

We start with an overview of hydrogen pathways. In 2019, c70MT of hydrogen was produced globally. 95% of it was grey, meaning it was derived from steam-methane reforming of natural gas. The cost of this process is around $1.3/kg ($11.5/mcf-gas- equivalent) and efficiency is c70%, which means that replacing 1 kWh of gas with 1kWh of hydrogen actually increases both gas demand and CO2 emissions.

Capture 80-100% of the CO2 from SMR using CCS and you have ‘blue hydrogen’, a fuel that costs c$2/kg ($18/mcfe), with a production efficiency of c60%, and a CO2 content that is 75-100% lower CO2 than combusting the natural gas it is derived from.

Finally, use renewable energy to hydrolyse water, and you have ‘green hydrogen’, which is truly zero carbon. But it currently costs $6-8/kg ($55-70/mcfe) and has 60-90% production efficiency, which is far worse than the best batteries we have researched.

Global hydrogen: market breakdown?

Can hydrogen be economic: in heat, power or transportation?

Costs matter for consumers in the energy transition. For example, we estimate that using blue hydrogen to decarbonize heat would raise an average household’s heating bill by c$670 per year, while green hydrogen would increase it by c$2,600. By contrast, our preferred solution of nature based solutions and efficient natural gas decarbonizes home heating at an incremental cost of $50 per household per year.

Decarbonize Heat?

Green hydrogen in the power sector does not look viable to us. We have modelled the green hydrogen value chain: harnessing renewable energy, electrolysing water, storing the hydrogen, then generating usable power in a fuel cell. Today’s end costs are very high, at 64c/kWh. Even by 2040-2050, our best case scenario is 14c/kWh, which would elevate average household electricity bills by $440-990/year compared with the superior alternative of decarbonizing natural gas.

Green Hydrogen Economy: Holy Roman Empire?

This is despite heroic assumptions in our 2040s numbers, such as a 1.5x improvement in round trip energy efficiency, 80% cost deflation, c40% “free” renewable energy, in situ hydrogen production and use, and nearby salt caverns for low cost storage (so green H2 retails at $3/kg). All of this analysis is based on transparent data and modelling, as shown below. We welcome pushbacks and challenges if you have different numbers.

Green hydrogen: the economics?

Hydrogen storage: the economics?

Fuel Cell Power Project Economics

Challenges are raised about green hydrogen in our work. First, processes fuelled purely by renewables (i.e., electrolysis reactors) will tend to have 30-40% utilization rates at best (half the US industrial average), which amortizes high capital costs over less generation. Second, storage is complex and could be 4-10x more expensive than we assumed, if salt caverns are not nearby. Finally, beware of ‘magic mystery deflation’ that is baked into the estimates of some commentators.

Economizing comes with trade-offs. This is particularly visible when we look at the cost of electrolysers, where lower capex may come at the cost of lower efficiency, reliability, longevity and even safety. Some forecasters are calling for 80% deflation, but we see 15-25% as more likely, if manufacturers wish to make a margin in the future, and as many of the cost components are technically mature.

Electrolysers: how much deflation ahead for hydrogen?

Green hydrogen in trucking may offer more promising inroads, particularly in well-chosen niches. Trucking consumes 10Mbpd of diesel globally and emits c1.5bn tons of CO2 per year, which is 3.5% of the global total. Current full-cycle costs of hydrogen trucks are c30% higher than diesels. This is based on $150k higher truck costs, 85% higher maintenance and $7/kg green hydrogen plus $1.5/kg retail margins.

But a full and rapid switch to hydrogen trucks in Europe would cost an incremental $50bn per year (equivalent to a 0.3% off Europe’s GDP, plus multipliers). 2040s green hydrogen truck costs could become competitive with diesel, in Europe, but again, this is incorporating some heroic assumptions. In particular, fuel retail margins for hydrogen may need to be c20x higher than for conventional fuels in remote locations with little traffic.

Green hydrogen trucks: delivery costs?

Immutable midstream issues: an anomalous commodity?

All of the value chains and models above assumed hydrogen was generated in situ, via electrolysis, at its point of use. However, in order for hydrogen to scale up, it would need to be transported, like other commodities.

Transporting hydrogen may be more challenging than any other commodity ever commercialised in the history of global energy. Costs are 2-10x higher than gas value chains. Up to 50% of hydrogen’s embedded energy may be lost in transit. We find these challenges are relatively immutable. They are due to physical and chemical properties of H2, plus the laws of fluid mechanics, which cannot be deflated away through greater scale.

Hydrogen: lost in transportation?

For example a hydrogen pipeline will inherently cost 2-10x more than a comparable gas pipeline. This is down to fluid dynamics, as the hydrogen line, all else equal, will flow 25% less energy (due to the gravity, energy density and compressibility of hydrogen gas), but require c30% more expensive reinforcement and materials (due to hydrogen’s lower molecular mass and proneness to causing embrittlement and stress cracking in high-pressure lines).

Gas pipelines, CO2 pipelines, hydrogen pipelines?

Moving hydrogen as ammonia is another option. Air Products recently sanctioned a $7bn project to produce green hydrogen in Saudi Arabia, convert it to ammonia, then ship the ammonia to Europe or Japan. Its guidance implies hydrogen could be imported at $10/kg while earning a 10% IRR. But we needed to assume several cost lines are budgeted at 50% below recent comparison-points to match this guidance. Our sense is that a comparably complex LNG project might warrant a 20% hurdle rate. Thus to be excited by this project, we would want to see a hydrogen sales price closer to $15/kg.

Transporting green hydrogen as ammonia or toluene?

Is Magic Mystery Deflation a Cure All?

The pushback to our hesitations is that deflation will prevail, costs will fall and green hydrogen will ultimately become economic in ways that are hard to model ex-ante. This is possible, but it is not borne out by our work reviewing over 1M patents. The ‘average’ topic in the energy transition is seeing c600 patents filed per year (ex-China) and accelerating at a 5% CAGR. Hydrogen fuel cells saw 222 in 2019 and are declining at a -10% CADR. Hydrogen trucks and fuelling stations saw c300 patents in 2019 which is flat on 2013.

Energy transition technologies: the pace of progress?

The patents also flag complexities. How do you safely prevent explosions in the event of a crash? How do you keep a fuel cell hydrated in dry climates, cool under thermal loads and starting smoothly in very cold climates? How do you add odorants to hydrogen to lower the risk of undetected leaks, if odorants poison fuel cells? Who is legally liable if a fuel cell is poisoned by inadvertently selling contaminated hydrogen?

We would be wary of companies that have made extensive promises, especially around future economics, but without having developed the underlying technologies being promised. This creates a high degree of risk.

To help identify technology leaders, we have assessed the patents filed in fuel cells, electrolyers, hydrogen vehicles and in fuelling infrastructure.

Fuel Cell Patents: twenty years of progress?

Hydrogen reformers: technology leaders

Hydrogen vehicles and fuelling stations: where’s the IP?

Conclusion. Policymakers are currently aiming to accelerate the development of green hydrogen. Our own work into the economics and technical challenges make us nervous that these policies may need to be walked back over time. There may be some interesting use cases for hydrogen in the energy transition (especially blue hydrogen). But the history of technology transitions does not suggest to us that a green hydrogen economy could emerge and have any meaningful impact on climate within the required 20-30 year timeframe.

Technology transitions: thinking fast and slow?