Category: Report

Vast quantities of gold hydrogen are produced in the Earth’s subsurface, via the serpentinization of iron-containing Peridotite rocks. Gold, white and orange hydrogen variations aim to harness this hydrogen. This 19-page note explores opportunities, costs and challenges for harvesting H2 out of natural seeps, hydrogen reservoirs or fracking/flooding Peridotites.

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110MTpa of global hydrogen is produced today, emitting 1.3GTpa of CO2, costing $0.8/kg. The market grows to 220MTpa by 2050, mostly blue H2, at $1.2-1.5/kg, per our hydrogen outlook, which is re-capped on page 2.

But what if gold hydrogen could be recovered from the subsurface of the Earth, analogous to the development of natural gas? Could the volumes, costs and CO2 intensities re-shape the future of hydrogen?

What is gold hydrogen? We have reviewed the geology from first principles, in two concise pages, covering the famous Bourakebougou hydrogen field in Mali, iron oxidation in ultra-mafic Peridotites, and radiolysis of water energized by the natural decay of Uranium, Thorium and Potassium. Details are on pages 4-5.

Hydrogen seeps offer the simplest way to access gold hydrogen. The main costs would be for gas separation. Hence we review the costs and CO2 intensities for cryogenics, swing adsorption and membranes, to derive some conclusions on this opportunity, on pages 6-9.

White hydrogen is the second broad opportunity and involves finding and producing hydrogen from reservoirs akin to conventional natural gas production. We model the costs of white hydrogen, CO2 intensities and their sensitivities on pages 10-12. But there are also reasons to question the geological risks for white hydrogen, per pages 13-14.

Orange hydrogen is the third broad opportunity, which engineers the production of hydrogen in the subsurface, by injecting water into fractured Peridotites. These could either be naturally fractured akin to waterflood projects, or hydraulically fractured akin to shales. We model the costs of orange hydrogen, CO2 intensities and sensitivities on pages 15-17.

Companies and conclusions are discussed in the final 2-pages of the report. Majors and Services are gearing up in gold hydrogen. But specifically, we profile ten earlier stage companies, from private companies to listed Australian equities, on pages 18-19.

The 19-page report is intended as a concise overview of all the key issues in gold hydrogen, focusing on the costs, CO2 intensities and challenges for each broad approach. For further details, please see our broader hydrogen research.

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Today’s power grids fire up peaker plants to meet peak demand. But the grid is changing rapidly. Hence this 17-page report outlines the economics of gas peaker plants. Rising volatility will increase earnings and returns by 40-50%, before grid-scale batteries come into the money for peaking?

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25% of global electricity came from burning 150bcfd of natural gas in 2023. An overview of simple-cycle gas turbines, combined-cycle gas turbines, and gas peaker plants is re-capped on pages 2-3.

There is a problem with levelized cost analysis. Peakers do not access ‘the same prices’ as other generation sources. They access the upper tail of a statistical distribution. This crucial point is outlined on pages 4-5.

That statistical distribution is lognormal. We show how actual power prices in actual grids tend to be lognormally distributed on pages 6-7.

The economics of gas peaker plants across different utilization rates and grid conditions can thus be properly quantified, on pages 8-9.

Rising volatility in global power markets results in higher standard deviations for power price distributions, and in turn, increases potential returns and earnings of peaker plants, as quantified on pages 10-11.

Is there upside or downside for gas peaker plants? Other supply-demand considerations are presented on page 12.

Will grid-scale batteries displace peakers? For the first time, we are able to properly compare the economics of gas peakers and grid-scale batteries, in a way that is truly apples for apples, on pages 13-14.

Which companies operate the most gas peakers? To answer this question, we have expanded our database of all US gas generation facilities and identified 30 of the largest fleets. Two listed IPPs stood out with relatively higher exposure to gas peakers, while ten of the larger companies are discussed on pages 15-17.

Sugar cane is an amazing energy crop, yielding 70 tons per hectare per year, of which 10-15% is sugar and 20-25% is bagasse. Crushing facilities create value from sugar, sugar-to-ethanol and cogenerated power. This 11-page note argues that more volatile electricity prices could halve ethanol costs or raise cash margins by 2-4x.

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Global biofuels production stands at 3.7Mboed. Half of this comprises 28 bn gallons pa of ethanol, of which 60% is from corn and 40% from sugar crops (page 2).

The sugar-to-ethanol value chain is different from the corn-to-ethanol value chain because it generates net electricity and heat via its waste products. It is also more productive as quantified on page 3.

Our base case costs for generating a 10% IRR on a new sugar-to-ethanol production facility require ethanol prices of $1.5/gallon, which is c5% lower than for corn ethanol. Numbers are explained on 4-5.

The costs of sugar feedstocks are a crucial, themselves depending on the costs of harnessing sugar from sugar cane. The best feedstock is not sugar but molasses, for the reasons on pages 6-7.

The angle that intrigues us for Brazilian biofuels is whether growing value in the bagasse for power generation could increase returns across the integrated value chain. Numbers and conclusions are on pages 8-10.

Dessert menu? We close by noting seven leading companies in sugar-based ethanol, including pure-plays in Brazil, India, broader global energy and food producers, such as AB Foods. Company notes are on page 11.

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The average major economy produces 70% of its own energy and imports the other 30%. This 12-page note explores energy security by country. We draw three key conclusions: into US isolationism; Europe’s survival; and the pace of EV adoption, both in China and in LNG-importing nations.

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Energy self-sufficiency can be defined in different ways. Our own preferred definition is explained on page 2. Our cross-plot of energy self-sufficiency by country is also shown on page 2.

This matters because energy is the lifeblood of all economic activity, while import dependency creates vulnerabilities amidst rising geopolitical tensions, as outlined on page 3.

Our first observation is that the US is entering a new era of foreign policy. Whatever the outcome of the upcoming US election, we fear that some commentators will increasingly call for an isolationist stance, for the reasons on pages 4-5.

Our second observation is an abysmal deterioration in Europe’s energy security, falling more than any other region, despite ramping wind and solar. Failure to unlock domestic resources is an existential threat to Europe’s security, and a missed opportunity for ESG oversight, as argued on pages 6-9.

Our third observation is that the rise of electric vehicles is heavily linked to different countries’ energy security. Most notably, China is substituting oil import reliance for domestic coal and renewables. But other regions may have less motivation to ramp electric vehicles, while doing so will largely increase LNG demand, as argued on pages 10-12.

The full note contains around 20 charts tabulating energy self-sufficiency by country and over time, as a useful reference, for this increasingly important metric.

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Arms race: defence versus decarbonization?

Energy self-sufficiency by country and over time?

This 17-page note outlines how capacity markets work, in order to stabilize global power grids. We argue reserve margins in the US grid are not as healthy as they look (in the chart above). Data-centers are like wolves at the door. Capacity prices must rise. This boosts gas plants, grid-scale batteries and non-regulated utilities?

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US grid resiliency is supported by c100 Reliability Standards written by NERC, enforced by FERC, and applicable to c100 balancing authorities, c325 transmission operators and c1,000 generation facilities in the US. Each violation can incur penalties up to $1M per day.

A key NERC Standard is to expect no more than 1 major grid outage per 10-year period, which in turn requires keeping reserve margins above 15%. Often quite far above. The evolution of these regulations is explained from first principles on pages 2-3.

The real challenge for resilient power grids is how to unlock sufficient long-term investment, aka the ‘missing money problem’. Different markets have capacity incentives in place, e.g., energy-only, centralized capacity markets, decentralized capacity markets. An overview of how capacity markets work is given on pages 4-5.

There might not seem to be any reason to worry about reserve margins given the title chart above. Yet we are worried (page 6) that demand will surprise to the upside (page 7), anticipated resources may underestimate renewables’ volatility (page 8), planning has become politicized (page 9) and some regions will deteriorate sharply (page 10).

What happens when reserve margins unexpectedly deteriorate? As a playbook, to inform our outlook, we provide some case studies from past data at ERCOT and CAISO on pages 11-13.

A key question in 2024 electricity markets is whether AI data centers could improve their time to market (see our AI video overview) amidst power grid bottlenecks by signing contracts to directly absorb large quantities of pre-existing power plants (e.g. per Amazon-Talen). If you think about how capacity markets work (pages 2-13), then data-centers are like a wolf at the door, for the reasons on page 14-15.

Capacity prices therefore need to increase, in order to safeguard today’s capacity chickens from the wolf at the door. We have attempted to quantify the necessary increases. This will flow through to the cash margins of gas turbines, nuclear facilities, grid-scale batteries, demand shifting contracts and non-regulated utilities, per pages 16-17.

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Energy transition is the largest construction project in history, with capex costs ultimately ramping up to $9trn per year. Overall, 40% of capex costs accrue to construction firms. Hence this 10-page note evaluates energy infrastructure construction companies, their EBIT margin drivers, and who benefits from expanding power grids?

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The past five years of research have led us to conclude that achieving net zero by 2050 would effectively require the largest energy infrastructure construction project in the history of human civilization, absorbing $9 trn pa of capital expenditures.

Whether or not you believe the world will hit its decarbonization goals, a construction boom increasingly seems to be imminent, linked to power grid bottlenecks and the rise of AI. Our quantifications of these rising capex costs are on pages 2-3.

Overall, 40% of capex costs accrue to construction firms, across different project types captured in our economic models. Some of our favorite examples, and different projects, are discussed on pages 4-5.

In particular, building in boom times can result in projects costing 2-3x more than building in normal times, per a note from 1Q24 that is worth re-visiting alongside this work, highlighting the value of engaging high-quality construction firms, and re-capped on page 6.

Hence we have screened 25 of the largest construction companies in the world. Generally, across our screen, we found that the average company has 100 years of operating history, employs 35,000 people, and generates $13bn pa of revenues.

Across these energy infrastructure construction companies, we evaluated which factors have impacted EBIT margins, on pages 7-8.

Specific companies include those with the most extensive history of delivering mega-projects across different sectors, those with the most specialized skill-sets, and those with particular specialization into power grid infrastructure. These companies are profiled on pages 9-10.

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Global energy capex: building in boom times?

Engineering and construction companies screen?

This 12-page note studies gas power plant generation profiles, across 10 of the largest gas plants in Australia, at 5-minute intervals, comparing 2024 versus 2014, amidst the rise of wind and solar. Ramping renewables to c30% of Australia’s electricity mix has not only entrenched gas-fired back-up generation, but actually increased the need for peakers?

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Australia’s electricity demand has increased at 0.9% per year in the past decade, reaching 273 TWH in 2023. 46% is still powered by coal, while 17% comes from gas.

Australia’s renewables generation has increased. Wind power generation has ramped 3x from 4% of Australia’s grid in 2013 to 12% in 2023, while solar has ramped 8x from 2% to 16%. For the data, please see our overview of each country’s grid mix.

So, what has happened to gas power plant generation profiles amidst the rise of renewables? To answer this question, we have tabulated 5-minute by 5-minute generation data, from AEMO, for ten of the largest gas power plants in Australia, in 2014 and 2024.

Gas is clearly backstopping the volatility of solar, per pages 2-4.

Hence, we have drawn five conclusions about the utilization rates of gas turbines, generation in MWH and capacity requirements in MW on pages 5-9 of the report (1-2 key charts support each conclusion).

Utilization rates have fallen at baseload gas generation facilities, which is inflationary. But utilization rates have increased at peaker plants.

It looks challenging to fully replace the flexibility of these gas turbines with grid-scale batteries, for the reasons on pages 9-10.

Conclusions, predictions and implications are summarized on page 11.

Power grids are truly amazing in their complexity, but tend to get over-simplified in energy transition roadmaps. In the words of Ludwig Wittgenstein, “don’t think, but look”.

Wittgenstein was probably not talking about gas power plant generation profiles. Yet our data show how ramping renewables have entrenched pre-existing gas turbines in the grid in Australia — similar to other analysis we have conducted in California, the UK and Europe — and arguably require c30% more peaker plants than a decade ago.

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This 13-page note summarizes the key conclusions across all of our research from 1H24, concisely, for busy decision-makers. We highlight 101 companies exposed to AI, which have come up in our recent work, to enable the rise of AI, and debottleneck its electricity supplies, out of 1,500 companies that have now crossed our screens overall.

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1,500 companies have been mentioned 2,500 times in our research since 2019, and our energy transition research now includes over 1,400 research notes, data-files and models. Hence this report is part of a quarterly series summarizing the key conclusions across our work.

In 1H24, the #1 theme that has excited the entire energy world has been the rise of AI. We estimate 150GW of AI data centers will be built by 2030. 40% will be in the US. This will underlie the largest period of new generation capacity growth in history.

Companies exposed to AI have thus featured heavily in our 1H24 research, as we tried to unravel the bottlenecks across capital goods, more capital goods, energy, utilities, infrastructure and materials.

In particular, we reached 15 thematic conclusions, and specific companies stood out alongside each conclusion, as outlined on pages 3-8.

We are less worried about materials bottlenecks biting in 2024 than we have been at other points in the past, but still excited by advanced materials, for the reasons on page 9.

Our energy outlook is more balanced than at other points in the past, albeit we think LNG will surprise to the upside and there is growing value in volatility, per page 10.

The most mentioned companies in our research in 1H24, and from 2019-2024 more broadly, are profiled on pages 11-13. Fourteen companies stand out, with angles that may be interesting to explore further.

The downside of a concise, 13-page report, is that it cannot possibly do justice to the depth and complexity of these topics. A TSE subscription covers access to all of the underlying research and data.

We are also delighted to elaborate on our energy transition conclusions from 1Q24, and discuss them with TSE clients, either over email or over a call.

Solar ramps from 6% of global electricity in 2023, to 35% in 2050. But could any regions become Solar Superpowers and reach 50% solar in their grids? And which regions will deploy most solar? This 15-page note proposes ten criteria and ranks 30 countries. The biggest surprises will be due to capital costs, grid bottlenecks and pragmatic backups.

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We are amending our solar growth forecasts in this research note, using ten criteria to rank the long-term competitiveness of solar in different nations, then screening 30 different nations globally.

Solar Superpowers could be capable of ramping solar to 50% of their power grids by 2050, but we think this would require meeting ten criteria…

Criteria #1-2 relate to solar insolation, and are explored on pages 3-4.

Criteria #3-4 relate to costs, impacting both the absolute levelized costs of solar, and the cost relative to other regional power prices.

Capital costs are among the most overlooked variables. Solar projects in Switzerland can be lower cost than in the sunny Sahara. See pages 5-6.

Criteria #5-6 are linked to solar siting. Further away from major demand centers, land is more available, and at lower costs. But this is counterbalanced by the cost to move power over longer distances, especially amidst grid bottlenecks. See the charts on pages 7-8.

Criteria #7-8 relate to grid integration and backups. These challenges present the greatest risks that could cause developed world countries to fall short of their solar ambitions, per pages 9-10.

Criteria #9-10 relate to incentives and competition, per pages 11-12.

Solar Superpower Scores are calculated for 30 countries, which comprised 75% of global electricity demand in 2023, and derived an average of 6% of their total power generation from solar over 2023. Results and surprises are discussed on pages 13-14.

The ultimate share of solar might reach 50% for Solar Superpowers, but we do not see any countries reaching this threshold. Australia and California come close. Different regions are discussed on page 15.

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Could renewables increase hydrocarbon realizations? Or possibly even double the value in flexible LNG portfolios? Our reasoning includes rising regional arbitrages, and growing volatility amidst lognormal price distributions (i.e., prices deviate more to the upside than the downside). This 14-page note explores the upside for energy trading in the energy transition. What implications and who benefits?

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Global energy markets are growing increasingly volatile, as argued in our January-2024 quantification of energy market volatility. Key reasons are the volatility of wind and solar, which are gaining share in the global energy system, as re-capped on pages 2-3.

In order to assess commodity price volatility, we have tabulated the statistical distributions of commodity prices, for a dozen major commodities, over the past 50-years. More volatile commodities generally have higher mean average prices, as shown on pages 4-5.

In order to model the impacts of rising volatility upon commodity prices, we need to fit a statistical distribution onto the commodity prices. Lognormal distributions provide a beautiful fit. Our confidence intervals for oil prices, gas prices and coal prices are outlined on pages 6-7.

How are commodity price realizations impacted by rising volatility? Mean outcomes exceed median-basis forecasts by a wider margin! The impacts of rising volatility on gas prices, coal prices and oil prices are quantified on pages 8-9.

How are the commodity price realizations available to energy trading businesses impacted by rising regional volatility? We argue that arbitrage potential will widen most in global LNG markets. Energy trading profits are often treated as one-offs. But they are one-offs that will tend to recur every quarter. We have quantified the growing value of diverting flexible LNG contracts to higher value markets on pages 10-13.

Global LNG: offtake contracts and spot market development?

LNG portfolios are most likely to benefit from rising volatility in the global energy system, as price spikes become more frequent, and higher prices are also required to mobilize a limited number of truly flexible LNG cargoes. 25 companies’ LNG portfolios are assessed on page 14.

We think this report should be required reading for anyone with commodity-exposed interests. Commodities are volatile. But as the energy transition progresses, there is value in volatility.

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