Increased natural gas prices have sent shockwaves into energy markets and pushed renewables up the agenda as they offer both perceived energy security and lower costs. However, simply switching to renewables is only part of the story. Full grid decarbonisation will need firming, requiring a trade-off between oversizing renewables, adding battery storage and using dispatchable backup power, whether it be fossil, hydrogen or biofuel based. Each option affects costs differently and location dictates which trade-offs are possible.
In this Insight, we investigate the costs of firm, low-carbon power in both the Middle East and Europe under dispatchable backup power configurations based on natural gas, green hydrogen or biofuel. Green hydrogen is produced from oversized and curtailed renewable power, then stored locally to generate power in times of low renewable output. Natural gas and biofuel (i.e. biogas) are assumed to use today’s infrastructure.
Full grid decarbonisation carries a cost premium
Renewables cannot generate on command. Therefore, although renewable electricity itself may be lower cost on a strict per MWh basis, additional battery storage and system oversizing add to total costs. Our analysis suggests a threshold at ~90% renewable penetration (n.b. varying by region) above which the levelised cost of electricity (LCoE) rises sharply.
As a result, CRU models renewable-heavy grids, with clean energy supplying only 95% of power, with the remaining 5% supplied by natural gas, acting as a flexible backup in order to reduce total costs of power.
However, such a configuration leads to issues that are relevant to this analysis. That is, although natural gas only represents 5% of annual power supply, the gas turbines must be sized to meet 100% of power demand in any given hour. As a result, low annual load factors will raise the cost per MWh delivered, because fixed costs remain constant regardless of utilisation. Fixed costs can also increase over the high utilisation baseline, as gas turbines at low load factors require frequent cycling, which adds to maintenance costs and reduces efficiency.
Below, we set out our estimates for costs of delivered power from a gas turbine operating at different load factors, at natural gas prices of $1.7 /GJ, representing an operation in Saudi Arabia.
Use CRU’s Energy Transition and Decarbonisation Service to find out more.
Renewable-heavy systems must be oversized to reduce the need for battery storage during periods of low generation, which can leave surplus energy unused.
In this analysis, we direct this surplus energy towards green hydrogen production that is stored locally and then used as an alternative to natural gas to provide flexible back up. This requires investment not only in electrolysers, but also hydrogen storage that is assumed here to be salt caverns in all cases (n.b. this may not be possible everywhere and more expensive storage options may be needed), as well as hydrogen ready turbines.
Green hydrogen production is costly, with renewable electricity comprising of >70% of total green hydrogen costs. However, in a renewables-heavy grid, surplus power that would have been curtailed has a near zero cost. This improves the economics, especially if a flexible electrolyser can run during periods of excess generation.
In the analysis below, we cover the results of renewable-heavy system costs, which provide firm power that is cost-optimised for renewables, battery and hydrogen storage – with dispatchable backup power provided by either natural gas or green hydrogen. High natural gas prices, up to $32 /GJ, are modelled to both reflect:
- Possible high natural gas prices in the future, but also
- The cost of biofuels, such as biomethane, that may also be used for flexible back up.
Accordingly, the analysis compares how natural gas, on-site green hydrogen and biofuels affect the overall cost of providing firm power from a renewables-heavy grid.
Renewables in the Middle East cannot compete with natural gas
Modelling of a solar-only, firmed, renewables-heavy system in the Middle East shows the expected relationship of costs rising as renewables penetration increases, particularly above a threshold of ~95%. A fully renewable system is modelled at ~7x higher cost than a natural gas-only system (i.e. ~$157 /MWh versus ~$23 /MWh). However, at natural gas prices of $1.7 /GJ, limiting renewables penetration to only 90% lowers costs to ~$82 /MWh (or only ~3.6x more costly than natural gas power), but such a grid would retain a residual emissions intensity of ~0.050 tCO2/MWh produced.
At the higher natural gas prices of $32 /GJ, renewables become the lower-cost option compared to gas-only power. However, this price level is included to reflect the cost of biofuels, such as biomethane, that might be used as dispatchable backup power to bring emissions down to zero, rather than as the main fuel source. The analysis indicates that the cost of using green hydrogen or biofuel for flexible backup is lowest at around 97% renewables penetration – approximately $100/MWh and $112/MWh, respectively. Even at these levels, both options cost more than natural gas backup at $1.7/GJ.
Moving from a natural gas-only grid with an emissions intensity of ~0.45 tCO2/MWh to one with an emissions intensity of ~0.050 tCO2/MWh (i.e. 90% renewables penetration) implies a carbon cost of ~$148 /tCO2 at a natural gas price of $1.7 /GJ. However, full grid decarbonisation, meaning the last 10% using hydrogen or biofuel, where emissions go from ~0.050 tCO2/MWh to zero, requires a carbon cost of $360–600 /tCO2. Decarbonising the last 10% of the grid costs up to 4x more than decarbonising the first 90%.
Green hydrogen potential for European backup power
Europe’s natural gas prices are much higher than the global average; and a heavy reliance on imports exacerbates vulnerabilities to price shocks. At typical historical natural gas prices of around $10/GJ, costs still rise as renewable penetration increases. With full grid decarbonisation, the optimised solar:wind mix has an estimated total cost of about $180/MWh. This is higher than the Middle East solar-only case at approximately $157/MWh. This illustrates how renewable costs are driven by latitude.
However, renewable-only power costs are ~1.6x those of gas-only power – a much lower ratio than for the Middle East, mainly due to the higher cost of gas-based power. Restricting renewables penetration to 90% limits the cost uplift to ~$134 /MWh, or only ~20% higher than the gas-only baseline but still ~60% higher than the Middle East.
At a higher natural gas price of $22/GJ, closer to current levels, increasing renewable penetration reduces overall costs, as shown in the graph below, taken from CRU’s Energy Transition and Decarbonisation Service. Gas-only power costs more than $160/MWh, compared with around $144/MWh at 90% renewables penetration. However, both options retain a residual emissions intensity of ~0.045 tCO2/MWh. To reduce the emissions intensity to zero, internally produced green hydrogen or biofuel bring power prices to ~$150 /MWh, assuming 90% renewables penetration. That is, green hydrogen would be on a par with biofuel flexible backup, even when taking into account the significant efficiency losses through the hydrogen power generation value chain.
These costs imply that moving from a natural gas-only grid with an emissions intensity of ~0.40 tCO2/MWh to one with an emissions intensity of ~0.045 tCO2/MWh implies a carbon cost of ~$70 /tCO2 at a natural gas price of $10 /GJ. However, for full grid decarbonisation – or in other words decarbonising the last 10% from ~0.045 tCO2/MWh to zero intensity using biofuel or hydrogen – requires a carbon cost of ~$350 /tCO2. That is, decarbonising the last 10% of the grid also has a cost up to 5x higher than decarbonising the first 90%.
Hydrogen could have a role in full grid decarbonisation
Green hydrogen produced from curtailed, or overbuilt, renewable power could play an economic role in achieving full grid decarbonisation in Europe but it is not expected in locations such as the Middle East. However, if a partially decarbonised grid is acceptable, even up to 90%, then natural gas would provide the most economic option in all but the highest gas price scenarios.
Natural gas as a dispatchable backup power maximises existing assets, but keeps Europe directly exposed to global energy markets and retains grid emissions of ~140 MtCO2/y in 2030. However, the impact of natural gas prices on power costs would be much lower than today.
Biofuels may remain linked to global energy prices but reduce further exposure. Biogas could use existing natural gas infrastructure but the constrained capacity of biofuel supply and demands from other sectors (e.g. cement, steel, aviation, agriculture, carbon removals) will affect availability and prices.
Green hydrogen that is locally produced would more fully eradicate energy security concerns, leading to stable prices, but would require significant infrastructure. A 90% renewables grid, with 10% hydrogen flexible backup, in Europe at 2050 power demand would require significant investment, including ~€5 tn for electrolysers alone, plus storage and hydrogen-compatible turbines.
If you are interested to understand more about power costs as grids decarbonise and what that might mean for costs across the commodity space, get in touch and we’ll be happy to discuss our thinking.
