Prevailing wind: new opportunities in grid volatility?

UK wind power has almost trebled since 2016. But its output is volatile, now varying between 0-50% of the total grid. Hence this 14-page note assesses the volatility, using granular, hour-by-hour data from 2020. EV charging and smart energy systems screen as the best new opportunities. Gas-fired backups also remain crucial to ensure grid stability. The outlook for grid-scale batteries has actually worsened. Finally, downside risks are quantified for future realized wind power prices.


This rise of renewables in the UK power grid is profiled on page 2, showing how wind has displaced coal and gas to-date.

But wind is volatile, as is shown on page 3, thus the hourly volatility within the UK grid is 2.5x higher than in 2016.

Power prices have debatably increased due to the scale-up of wind, as shown on page 4.

But price volatility measures are mixed, as presented on pages 5-6. We conclude that the latest data actually challenge the case for grid-scale batteries and green hydrogen.

Downside volatility has increased most, as is quantified on pages 7-8, finding a vast acceleration in negative power pricing, particularly in 2020.

The best opportunities are therefore in absorbing excess wind power. EV charging and smart energy systems are shown to be best-placed to benefit, on pages 9-10.

Upside volatility in power prices has not increased yet, but it will do, if gas plants shutter. The challenge is presented on pages 11-13, including comparisons with Californian solar.

Future power prices realized by wind assets are also likely to be lower than the average power prices across the UK grid, as is quantified on page 14. This may be a risk for unsubsidized wind projects, or when contracts for difference have expired.

Geothermal energy: what future in the transition?

Drilling wells and lifting fluids to the surface are core skills in the oil and gas industry. Hence could geothermal be a natural fit in the energy transition? This 17-page note finds next-generation geothermal economics can be very competitive, both for power and heat. Pilot projects are accelerating and new companies are forming. But the greatest challenge is execution, which may give a natural advantage to incumbent oil and gas companies.


The development of the geothermal industry to-date is summarized on pages 2-4. We also explain the rationale for geothermal in the energy transition.

The costs of a geothermal projects can be disaggregated across wells (page 5), pumping (page 6-7) and power turbines (pages 8-9). We draw out rules of thumb, to help you understand the energy economics.

The greatest challenge is geological complexity, as argued on page 10. It is crucial to find the best rocks and mitigate execution risks.

Base case economics? Our estimates of marginal costs are presented for traditional geothermal power (page 11), next-generation deep geothermal electricity (page 12) and using geothermal heat directly (page 13).

Leading companies are profiled on pages 14-16, after tabulating 8,000 patents. We also reviewed incumbent suppliers, novel pilots, and earlier-stage companies.

We conclude that geothermal energy is a natural fit for incumbent oil and gas companies to diversify into renewables, and arguably a much better fit than wind and solar (page 17).

Biomass and BECCS: what future in the transition?

20% of Europe’s renewable electricity currently comes from biomass, mainly wood pellets, burned in facilities such as Drax’s 2.6GW Yorkshire plant. But what are the economics and prospects for biomass power as the energy transition evolves? This 18-page analysis leaves us cautious.


Arguments in favor of biomass are outlined on pages 2-3, using the carbon cycle to show how biomass could be considered zero-carbon in principle.

Examples of biomass power plants are described on pages 4-5, focusing upon Drax and RWE, and drawing upon data from 340 woody biomass facilities in US power.

The economics of producing biomass pellets are presented on pages 6-7, including a detailed description, capex breakdown, and critique of input assumptions.

The economics of burning biomass pellets to generate electricity are presented on pages 8-9, again with a detailed description and critique of input assumptions.

The economics of capturing and disposing of the CO2 are presented on pages 10-12, allowing us to build up a full end-to-end abatement cost for BECCS.

Energy economics are disaggregated on pages 13-14, in order to derive a measure of energy return on energy invested (EROEI) and CO2 intensity (in kg/kWh). Surprisingly, we find the EROEI for BECCS to be negative.

Is it sustainable? We answer this question on 15-17, arguing that biomass energy and BEECS, properly considered, both have a higher CO2 intensity than gas.

Conclusions and implications are presented on pages 18, including bridges for the total CO2 intensity of biomass and BECCS.

Decarbonized power: how much wind and solar fit the optimal grid?

What should future power grids look like? Our 24-page note optimizes cost, resiliency and CO2, using a Monte Carlo model. Renewables should not surpass 45-50%. By this point, over 70% of new wind and solar will fail to dispatch, while incentive prices will have trebled. Batteries help little. They raise power prices by a further 2-5x to accommodate just 3-15% more renewables. The lowest-cost, zero-carbon power grid, we find, comprises c25% renewables, c25% nuclear and c50% decarbonized gas, with an incentive price of 9c/kWh.


Pages 2-4 illustrate the volatility of wind and solar generation at today’s grid penetration, providing rules of thumb around intermittency.

Pages 5-6 illustrate the strange consequences once renewables surpass 25% of the grid, including curtailment, negative power pricing and financing difficulties.

Pages 7-9 quantify and explain how much curtailment will take place in a typical grid as renewables scale from 25% to 40%, 50% and 60% of gross generation, using a Monte Carlo approach. The model shows when and why curtailment is occurring.

Pages 10-20 quantify and explain the costs of batteries, to backstop renewables as they scale from 25%, to 40%, 50% and 60% of the grid, while avoiding curtailment. Real world conditions are not conducive to competitive battery economics.

Pages 21-23 quantify the residual reliance on natural gas. Amazingly, even our most aggressive battery scenarios only permit 10% of gas-power capacity to be shuttered. Low-utilization gas is costly. High-utilization gas is less costly. And the economics of decarbonized gas are superior to any renewables plus batteries combination.

Page 24 concludes that natural gas will emerge as the ‘best battery’ to backstop renewables, estimating the most likely shares in an optimal power mix.