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The compelling reason why fossil fuel producers will be needed even beyond 2050 is that they currently provide over 80% of global energy, and 90% of the world’s population still needs the wealth creation that energy delivers, says Schalk Cloete. Given that, he summarises his co-authored paper that takes a close look at how a fossil exporter, Norway, can trade with an importer, Germany, while decarbonising. The modelling focusses on electricity trade via HVDC cables, hydrogen trade via pipelines, CCS via continued use of natural gas pipelines and construction of CO2 pipelines, and trading in energy-intensive industrial base products exemplified by steel. A point that’s often overlooked: you don’t have to export hydrogen (will all the associated transport and infrastructure costs) when you can use your hydrogen to make a globally needed commodity like steel that is easily exported. While fossil producers are raking in profits due to the Russia-Ukraine war, now is the time for them to start making the change, says Cloete.

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Few people realise how cheap and practical fossil fuels truly are. As a simple illustration, Figure 1 shows the costs of producing oil, gas, and coal for the next 100 years at 2019 production rates. Even when including a 50 $/ton CO2 tax (the average social cost of carbon), we can supply the next century of fossil fuels for one third the cost of mid-century solar hydrogen. Furthermore, hydrogen is substantially less practical and cost-effective to store and trade than natural gas due to its 3x lower volumetric energy density, and this disadvantage grows far larger when compared to oil and coal.

Figure 1: The cost of supplying fossil fuels for the next 100 years at 2019 production rates derived from Welsbey et al. Solid lines are actual production costs and dashed lines include a 50 $/ton CO2 tax. Green H2 from solar PV operating at a 20% capacity factor with half a day of H2 storage are included for perspective by assuming optimistic mid-century solar and electrolyzer costs of 350 $/kW and H2 storage tank costs of 15 $/kWh.

Many people want the world to leave most of this cheap and practical energy in the ground – a deeply naïve notion when we consider that a mere 10% of the projected peak human population has thus far reached decent living standards (Figure 2). Imagining all the additional housing, factories, commercial districts, schools, hospitals, roads, vehicles, and other labour-saving devices we must build to rectify this gross global injustice quickly brings home the absurdity of the “leave it in the ground” initiative.

Figure 2: Six out of every seven world citizens live on less than $1,000 a month (the vertical line) and one out of every four on less than $100 a month (please take a moment to imagine what that must be like) / Graph from Gapminder

Figure 3 shows the obvious result: Fossil fuel demand will remain stubbornly high despite the deafening noise around “net-zero by 2050.” The very real danger of this situation is that increasingly desperate and erratic green politics fuel inflation and stunt developing world growth, escalating the cost of the transition and reducing the willingness and ability to pay this cost. Current events offer a first taste of what we may expect from such a dysfunctional transition effort.

Figure 3: The inevitable divergence between short-term forecasts for oil, gas, and coal demand (solid lines) and requirements in the net-zero by 2050 scenario (dotted lines).

Our best strategy for mitigating this potentially disastrous scenario is true technology neutrality, i.e., a CO2 price replaces all technology-specific incentives. In such a framework, all technologies, fossil fuels included, will be allowed to participate fairly in the energy transition. The fossil fuel industry (which still supplies 83% of global energy and quite literally keeps all of us alive) will then be able to invest with confidence to simultaneously ensure affordable energy security and reduce emissions.

The striking effect of such a paradigm shift will be a surprisingly rapid decarbonisation of energy exports from oil & gas producers. As an example, Figure 4 illustrates the large cost advantage that suppliers of cheap conventional natural gas will maintain in the production of clean and tradeable fuels like ammonia over green alternatives produced from the world’s best solar resources. The profit potential inherent in such a large cost advantage will drive rapid technology deployment when CO2 pricing around the world reaches the required level.

Figure 4: The cost of supplying blue and green ammonia at mid-century costs from Middle Eastern resources / Natural gas resource curve from Welsbey et al. and NH3 production costs from Arnaiz & Cloete.

The remainder of this article will share some detailed results from our recent study of what natural gas export decarbonisation might look like in Northern Europe.

Our model was designed to facilitate a detailed investigation into the different energy trade connections between Norway (an energy exporter) and Germany (a large energy importer). Four channels for low-carbon energy trade were investigated (Figure 5):

Electricity, hydrogen, and CO2 can be traded only between Norway and Germany, whereas natural gas and steel are traded on a broader international market. Cheap and simple intercontinental trade is a major advantage of steel as a clean energy export vector relative to hydrogen.

11 different electricity generation technologies, 4 hydrogen production technologies, 4 energy storage technologies, and an H2-DRI steelmaking process were included for consideration in the optimisation.

Figure 5: An illustration of the various connections modelled between Norway and Germany, which is divided into two parts. For an explanation of the numbering, please refer to Table 2 in our paper.

We made our assumptions as favourable toward green technologies as possible so that any conclusion that may prove favourable to fossil fuels cannot be questioned. Here is a list of these assumptions:

The base/central scenario assumes that Germany does not permit any CO2 capture and storage (CCS), while Norway uses CCS as an option to decarbonise its natural gas exports. Germany remains open to import blue hydrogen and steel made from blue hydrogen if it is competitively priced.

Next to this central scenario, a green scenario and a blue scenario are considered. In the green scenario, no CCS is allowed either in Norway or Germany, whereas the blue scenario allows CCS in Germany as well. However, CO2 storage still does not take place in Germany and the produced CO2 gets piped back to Norway to be stored in North Sea reservoirs.

Each scenario was modelled with and without permitting Germany to import its steel demand.

Figure 6 shows the high degree of interconnection between the three modelled regions in terms of electricity trade.

South Germany has the most volatile profile due to its high reliance on solar PV. The large daily solar peaks are balanced mainly by electricity trade, supported by pumped hydro, batteries, and a small amount of green hydrogen production. Electricity supply during night-time comes mainly from Norwegian hydropower imports.

Figure 6: Optimised hourly electricity profiles for the three modelled regions for a two-week period in April in the central scenario with steel trade.

North Germany, with its better wind resources (including offshore wind), does not deploy solar. It acts as a thoroughfare of electricity trade between Norway and South Germany and contributes with a considerable amount hydrogen-fired power generation (mostly burning blue hydrogen imported from Norway) during times of very low wind output. A small amount of green hydrogen is also produced when South German solar generation is at its highest.

Norway exports large amounts of electricity to Germany using a large fleet of offshore wind power supported by flexible hydropower generation. It also uses a constant load of electricity (in combination with blue hydrogen) to produce clean steel for export to the international market. A small amount of natural gas-fired power production with CCS via the gas switching reforming (GSR) technology is deployed during the hours with the lowest wind output.

The overall performance of the three scenarios with and without steel trade is summarised in Figure 7.

Focussing on the base case first (two left-most columns in the graphs), Figure 7b shows that Norway displaces a considerable portion of its hydrogen exports with steel exports when steel trade is allowed. As a result of the larger quantity of blue hydrogen consumed for steel production, the price of hydrogen (dashed line in Figure 7c) increases, which increases profitability for Norway. The result is net-negative energy system costs in Norway (dashed line in Figure 7b).

When looking at the green scenarios (middle two columns in the graphs), Figure 7b shows that Norway now exports almost no hydrogen because green hydrogen is about twice as expensive as blue hydrogen (Figure 7c). Instead, Norway exports all its natural gas production directly, leading to significant indirect emissions (dashed line in Figure 7a). Now, Germany needs to produce its own green hydrogen, requiring considerably larger electricity production (Figure 7a). A substantial part of that hydrogen is used to make steel, so the allowance for steel imports in the “green steel” scenario causes a large reduction in power consumption for producing green hydrogen.

The blue scenarios (two right-most columns in the graphs) show that Germany now imports natural gas, makes its own blue hydrogen and sends the resulting CO2 back to Norway. Although it is somewhat more expensive to transport natural gas to Germany and transport CO2 back than to transport hydrogen only, Germany benefits in this scenario from producing blue hydrogen via the flexible GSR technology that assists in balancing its large fleet of mandated wind and solar power. Figure 7b shows that, when steel trade is not allowed, Norway exports all its natural gas and imports a large amount of CO2 from Germany. However, when steel trade is enabled in the “blue steel” scenario, Norway converts all its natural gas locally into blue hydrogen to produce more profitable steel for export (bringing Norway’s energy system cost to negative numbers once more). In this steel trade scenario, Germany must import natural gas from elsewhere but still sends the resulting CO2 to Norway for storage.

In terms of costs, electricity prices vary little between the three scenarios, although electricity in the green scenario is somewhat more expensive. Electricity prices have little scope for variation because the electricity mix in Figure 7a is strongly constrained by the policy mandate of 80% renewables in Germany and 95% in Norway. However, hydrogen and steel prices vary substantially. In general, blue hydrogen is about half as costly as green hydrogen. This difference in hydrogen prices also affects steel prices since all steelmaking uses hydrogen as the primary energy input in the simulation. However, since the final demand for hydrogen is assumed to be 4x smaller than that of electricity in the model (and the cost of other fuels like biomass and imported synfuels is ignored), the effect of more expensive hydrogen in the green scenarios does not inflate the overall system cost excessively.

Figure 7: Results from the assessment of the three scenarios without and with steel trade. Electricity generation, emissions, system costs, and commodity prices are aggregated across all three nodes. In panel a), CO2 in NG exports refers to the CO2 emissions potential of exported natural gas. In panel b), steel and CO2 trade flows are presented in energy equivalents: 2.79 MWh of hydrogen and electricity per ton of steel and 4.87 MWh of combusted natural gas per ton of stored CO2. In panel c), the steel premium is the difference between German steel prices and the assumed world export price of 450 €/ton and “Others” include electrolysers, batteries, pumped storage, hydrogen storage, and natural gas export profits.

A key finding from this study is that natural gas producers like Norway can continue to enjoy substantial export profits in a net-zero world. The fundamental reason behind this finding is that blue hydrogen made from natural gas at its cost of production is far cheaper than green hydrogen. If the supply of blue hydrogen is insufficient so that some green hydrogen must be produced to satisfy demand, green hydrogen will set a market price that is well above the production cost of blue hydrogen, leading to large and sustained profits for blue hydrogen exporters.

For example, Norway can produce natural gas, which is the feedstock for blue hydrogen, for less than 10 €/MWh. In contrast, a meaningful amount of green hydrogen production in Norway must be made from electricity approaching 70 €/MWh shown in Figure 7c. Small quantities of green hydrogen can be produced using excess wind and solar power at electricity prices near zero, but the resulting low utilisation rate of electrolysers and hydrogen storage facilities means that even this initial fraction of green hydrogen is more expensive than blue hydrogen.

Since sustained export profits for natural gas producers in a net-zero world rests on blue hydrogen demand exceeding supply, a large and diversified global export market is essential. Although direct hydrogen trade will always be regionally constrained, a broad range of easily tradeable industrial base products (such as steel) can facilitate access to global markets.

This analysis clearly showed that natural gas exporters can use blue hydrogen and easily tradeable derivatives like steel and other metallurgical, chemical, calcined, or ceramic products to maintain long-term profitability in a net-zero world.

Unlocking this potential will require considerable investment from the oil & gas industry in blue hydrogen production facilities and the associated downstream CO2 handling infrastructure. Since CO2 transport and storage is essentially oil & gas production in reverse, the industry is perfectly positioned to rapidly expand such a network at a low cost. The cost could even be negative if the resulting CO2 can be used to access more hydrocarbons that can be converted to blue hydrogen to extract the stored energy without associated emissions. Furthermore, oil & gas exporters must build local industrial clusters producing easily tradeable industrial base products to access diversified global markets.

The oil & gas industry cannot expect the generous policy support given to green alternatives. Luckily, such support is not needed. As the ongoing global energy crunch illustrates, extraordinary profits await every time energy markets become badly imbalanced. A relatively small fraction of these profits will be enough to trigger this transition. For example, Norway is currently raking in about €100 billion in oil & gas profits each year. Investing a mere 3% of this profit in 2.5 GW of blue hydrogen production capacity (with the associated CO2 handling infrastructure) will avoid as much CO2 as electrifying the entire Norwegian car fleet.

Due to the combined actions of activist investors and Russia, these extraordinary profits will last for some time. Also, if we insist on continuing with fossil fuel divestment and green technology-forcing instead of technology-neutral carbon pricing as our primary decarbonisation strategies, such episodes will be repeated at regular intervals across the energy transition. Thus, the oil & gas industry will only have itself to blame if it fails to invest these windfalls in securing long-term profitability via blue hydrogen and industrial base products.

Schalk Cloete is a research scientist studying different pathways for decoupling economic development from emissions and environmental degradation

Filed Under: Energy, Oil, Gas & Coal Tagged With: CCS, decarbonisation, electricity, exports, gas, Germany, hydrogen, imports, industry, Norway, pipelines, steel, Transmission

My work on Energy Post is focused on the great 21st century sustainability challenge: quadrupling the size of the global economy, while reducing CO2 emissions to zero. I seek to contribute a consistently pragmatic viewpoint to the ongoing debate on this crucial topic. My formal research focus is on second generation CO2 capture processes because these systems will be ideally suited to the likely future scenario of a much belated scramble for deep and rapid decarbonization of the global energy system.

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