Hydrogen: lost in transportation?

Transporting hydrogen will be more challenging than for any other commodity ever commercialised in the history of global energy. This 19-page note reviews the costs and complexities of cryogenic trucks, hydrogen pipelines and chemical hydrogen carriers (e.g., ammonia). Midstream costs will be 2-10x higher than comparable gas value chains, while up to 50% of hydrogen’s embedded energy may be lost in transportation.


We have assessed the costs of green hydrogen value chains in our prior research, focusing on power and trucking. The costs are re-capped on pages 2-3. But our calculations assume all hydrogen is generated near its point of sale. This note assesses the additional costs and complexities of hydrogen transport.

Hydrogen is inherently more complex to transport than natural gas, due to immutable physical and chemical differences, which are spelled out on pages 4-5.

Cryogenic trucks are assessed on pages 6-7. Liquefying hydrogen at -253C and the associated boil-off may consume c50% as much energy as is in the delivered hydrogen.

New hydrogen pipelines are assessed on pages 8-12, including a deep-dive into the fluid mechanics. Costs will inherently be 2-10x higher than for natural gas.

Blending hydrogen into pre-existing gas pipelines is assessed on pages 13-14. This option introduces unfathomable complexity for a mere 3-6% CO2 reduction.

Chemical carriers such as ammonia are assessed on pages 15-17. We model the value chain end-to-end, which makes for interesting conclusions on Air Products’s recently sanctioned $7bn hydrogen-ammonia project in Saudi Arabia.

The impact on hydrogen costs is quantified on pages 18-19. We conclude hydrogen transport would increase our power and trucking costs by c10-25%.

The future of offshore: fully subsea?

Offshore developments will change dramatically in the 2020s, eliminating new production platforms in favour of fully subsea solutions. The opportunity can increase a typical project’s NPV by 50%, reduce its breakeven by one-third and effectively eliminate upstream CO2 emissions. We have reviewed 1,850 patents to find the best-placed operators and service providers, versus others that will be disrupted. Overall, the theme supports the ascent of low-carbon natural gas, which should treble in the energy mix by 2050. This 22-page note presents the opportunity.


The offshore oil and gas industry’s progress towards ‘fully subsea’ developments, without any platforms or surface infrastructure being necessary, is reviewed in detail in pages 2-5, covering key projects and milestones from 1985-2000.

30% economic savings in both capex and opex are quantified line-by-line, across c50 cost lines, in pages 6-9.

1.5x NPV uplifts and 4pp IRR uplifts are quantified by modelling a representative fully greenfield gas-condensate project on pages 11-12.

CO2 emissions can be virtually eliminated by a fully subsea development solution. Pages 12-13 add up the impacts of higher efficiency, power from shore, fewer materials and the elimination of PSV/helicopter trips.

The key engineering challenges for fully subsea systems, which remain to be resolved, are summarized on page 14.

Who benefits from the trend toward fully subsea systems, is described from page 15 onwards after reviewing 1,850 patents around the industry. This includes both the leading service companies and operators (primarily Equinor, but also TOTAL, Shell).

The leaders in subsea compression technology are assessed on pages 16-17.

The leaders in subsea power systems are described on pages 18-19.

The leaders in next-generation subsea robotics are assessed on pages 20-21.

Others are disrupted, as is described in detail in page 22.

Covered service companies in the report include ABB, Aker, Eelume, GE, Kraken, Oceaneering, OneSubsea, Saipem, Siemens, Technip-FMC, Wood Group, the PSV and helicopter sector, and c20 early stage companies in next-generating subsea robotics.

Ten Themes for Energy in the 2020s

We presented our ‘Top Ten Themes for Energy in the 2020s’ to an audience at Yale SOM, in February-2020. The audio recording is available below. The slides are available to TSE clients, in order to follow along with the presentation.


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Updated 2nd April, 2019.

Thunder Said Energy Policy for the Processing of Data Governed by GDPR

Thunder Said Energy may collect, process or handle Personal Data relating to its customers or prospective customers (“customers”) in the European Economic Area (“Personal Data”).

Thunder Said Energy’s relationship with its customers is governed by our terms of use (above), privacy policy (above), and potentially other commercial agreements. It is also legally bound under the EU General Data Protection Regulation 2016/679 (“GDPR”) in its collection, uses, and processes around Personal Data.

This Policy describes Thunder Said Energy’s commitment to the processing of Personal Data under the GDPR.

Please contact [email protected] if you would like an executed version of this Policy, or for answers to any GDPR queries arising from thie policy.

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4. Transfers to non-EEA Countries. Most of the Personal Data collected by Thunder Said Energy will be collected via its US-website. Where Personal Data are disclosd Thunder Said employees in the EEA, they may be transferred to Thunder Said Energy’s office in Connecticut, United States. Every effort will be made to ensure the transfer is fully secure. Personal data is not expected to be transmitted to other destinations, beyond the United States and EEA.

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8. Personal Data Breach. In the event of a Personal Data breach under GDPR, Thunder Said Energy will notify its applicable customers without undue delay after becoming aware of the breach. Such notification(s) may be delivered to an email address provided by Customer or by direct communication (for example, by phone call or in-person). The customer is responsible for ensuring any email address provided by them is current and valid. Thunder Said Energy will take reasonable steps to provide information reasonably required.

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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.

Electric Vehicles Increase Fossil Fuel Demand?

It is widely believed that electric vehicles will destroy fossil fuel demand. We find they will increase it by 0.7Mboed from 2020-35. EVs only start lowering net fossil fuel demand from 2037 onwards. The reason is that 3.7x more energy is consumed to manufacture each EV than the net road fuel it displaces each year; while the manufacturing of EVs is seen growing exponentially. The finding is a strong positive for natural gas, as outline in our new 13-page note.


Pages 2-3 outline our oil demand forecasts out to 2050, reflecting the rise of electric vehicles and six other game-changing technologies.

Pages 4-5 lay out the energy economics of producing electric vehicle batteries, based new, granular details from the recent technical literature.

Pages 6-9 model the exponential rise of electric vehicles, and how rapidly increasing manufacturing energy could outweight slowly increasing fuel savings.

Pages 10-13 consider pushbacks to our thesis, including the use of renewable technology, battery innovations or vehicle autonomy.

MCFCs: what if carbon capture generated electricity?

Molten carbonate fuel cells (MCFCs) could be a game-changer for CCS and fossil fuels. They are electrochemical reactors with the unique capability to capture CO2 from the exhaust pipes of combustion facilities; while at the same time, efficiently generating electricity from natural gas. The first pilot plant was due to be tested in 1Q20, by ExxonMobil and FuelCell Energy, but was deferred. Economics range from passable to phenomenal. The opportunity is outlined in our 27-page report.


Pages 2-4 outline the market opportunity for more efficient carbon separation technologies, which can be retrofitted to 4TW of pre-existing power plants, without adding $50/T of cost and 15-30% of energy penalties per traditional CCS.

Pages 5-13 outline how MCFCs work, including their operation, development history, how recent patents promise to overcome reliability problems, and their emergent adaptation to carbon capture.

Pages 14-18 assess the economics, both in absolute terms, and by comparison to new gas plants and hydrogen fuel cells. CCS-MCFC economics range from passable to phenomenal, at recent power prices.

Pages 19-23 suggest who might benefit. FuelCell Energy has received $60M investment from ExxonMobil, hence both companies’ prospects are explored.

Appendix I is an overview of incumbent CCS technologies, and their limitations.

Appendix II is an overview of six different fuel cell types, comparing and contrasting MCFCs.

Global gas: catch methane if you can?

Scaling up natural gas is among the largest decarbonisation opportunities on the planet. But this requires minimising methane leaks. Exciting new technologies are emerging. This 23-page note ranks producers, positions for new policies and advocates developing more LNG. To seize the opportunity, we also identify 23 early-stage companies and 10 public companies in methane mitigation. Global gas demand should treble by 2050 and will not be derailed by methane leaks.


Pages 2-4 explain why methane matters for climate and for the scale up of natural gas. If 3.5% of methane is leaked, then natural gas is, debatably, no greener than coal.

Pages 5-8 quantify methane emissions and leaks across the global gas industry, including a granular breakdown of the US supply-chain, based on asset-by-asset data.

Page 9-10 outlines the incumbent methods for mitigating methane, plus our screen of 34 companies which have filed 150 recent patents for improved technologies.

Pages 11-13 cover the best new developments in drones and robotics for detecting methane emissions at small scale, including three particularly exciting companies.

Pages 14-15 outline next generation satellite technologies, which will provide a step-change in pinpointing global methane leaks and repairing them more quickly.

Pages 16-20 covers the changes underway in the oilfield supply chain, to prevent fugitive methane emissions, highlighting interesting companies and innovations.

Page 20-21 screens methane emissions across the different Energy Majors, and resultant CO2-intensities for different gas plays.

Pages 22-23 advocate new LNG developments, particularly small-scale LNG, which may provide an effective, market-based framework to mitigate most methane.

Ramp Renewables? Portfolio Perspectives.

It is often said that Oil Majors should become Energy Majors by transitioning to renewables. But what is the best balance based on portfolio theory? Our 7-page note answers this question, by constructing a mean-variance optimisation model. We find a c0-20% weighting to renewables maximises risk-adjusted returns. The best balance is 5-13%. But beyond a c35% allocation, both returns and risk-adjusted returns decline rapidly.


Pages 2-3 outline our methodology for assessing the optimal risk-adjusted returns of a Major energy company’s portfolio, including the risk, return and correlations of traditional investment options: upstream, downstream and chemicals.

Page 4 quantifies the lower returns that are likely to be achieved on renewable investment options, such as wind, solar and CCS, based on our recent modeling.

Pages 5-6 present an “efficient frontier” of portfolio allocations, balanced between traditional investment options and renewables, with different risk and return profiles.

Pages 6-7 draw conclusions about the optimal portfolios, showing how to maximise returns, minimise risk and maximise risk-adjusted returns (Sharpe ratio).

The work suggests oil companies should primarily remain oil companies, working hard to improve the efficiency and lower the CO2-intensities of their base businesses.

Disrupting Agriculture: Energy Opportunities?

Precision-engineered proteins are on the cusp of disrupting the meat industry, according to an exceptional, 75-page report, published recently by RethinkX. The science is rapidly improving, to create foods with vastly superior nutrition, superior taste and superior costs, by the early-2020s.

The energy opportunities are most exciting to us, after reading the report. If RethinkX’s scenarios play out, we estimate: direct CO2 savings of 400MTpa, enough to offset 10% of US oil demand; 2bcfd of upside to US gas demand; and enough land would be freed up to decarbonise all of US oil demand, or increase US biofuels production by 6x to c6Mbpd.

We would be delighted to introduce clients of Thunder Said Energy to the reports’ authors, Catherine Tubb and Tony Seba. Please contact us if this is useful.

CO2-EOR in shale: the holy grail?

What if there were a technology to sequester CO2, double shale productivity, earn 15-30% IRRs and it was on the cusp of commercialization? Promising momentum is building, at the nexus of decarbonised gas-power and Permian CO2-EOR…

First, this week, we finished reviewing 350 technical papers from the shale industry’s 2019 URTEC conference. The biggest YoY delta is that publications into EOR rose 2.3x. CO2-EOR is favored (chart below). Further insights from the technical literature will follow in a detailed publication, but importantly we do not see underlying productivity growth in shale to be slowing.

Second, we re-read Occidental Petroleum’s 2Q19 conference call. More vocally than ever before, Oxy hinted it could take the pure CO2 from decarbonised power plants and use it for Permian-EOR; with its equity interest in NetPower, 1.6M net Permian acres, and leading CO2-EOR technology. Quotes from the call are below:

  • On CO2-EOR: “We are investing in technologies that will not only lower our cost of CO2 for enhanced oil recovery in our Permian conventional reservoirs, but will also bring forward the application of CO2 enhanced oil recovery to shales across the Permian, D.J. and Powder River basins”
  • On decarbonised gas power: “What it does is, it takes natural gas combines that with oxygen and burns it together, and that’s what creates electricity and it creates that electricity at lower costs… one of our solutions is to put that in the Permian… for use in our enhanced oil recovery… It will utilize our gas that that if we sold it would make nearly as much”.
  • On the opportunity: “We are getting calls from all over the world, with people wanting our help to — figure out how to capture CO2 from industrial sources, and then what to do with it and oil reservoirs”.

Our extensive work on these themes includes two deep-dive reports linked above. Our underlying models can connect c10% IRRs on oxy-combustion gas plants (first chart below) with 15-30% IRRs at Permian CO2-EOR (second chart below). On these numbers, the overall NPV10 of an integrated system could surpass $10bn.

EOR remains one of the most exciting avenues to boost Permian production potential. So far, our shale forecasts assume little direct benefit (chart below). But an indirect benefit is implicit, as we assume 10% annualized productivity growth to 2025, which would underpin a very strong ramp-up (chart below). 2023-25 currently look well-supplied in our oil market model, due to falling decline rates, but this could be compounded by CO2-EOR.

We are more positive on the ascent of gas, stoked by increasing usage in decarbonised power. We see potential for gas demand to treble by 2050.