Category: Report

Could electric vehicles deflate towards cost parity with ICEs in 2025-30, helping to re-accelerate EV adoption? This 12-page report into electric vehicle cost parity contains a granular sum-of-the-parts cost breakdown. Then we consider battery deflation, power train deflation, small urban EVs, tax incentives, and the representativeness of low-cost Chinese EVs.

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Electric vehicles may saturate at 15-30% of global vehicle sales in 2025-30, well below consensus forecasts, and even our own forecasts from a year ago which saw EVs reaching 50% of global vehicle sales by 2030. This would strongly impact energy, materials and capital goods.

Sometimes a thesis is so important that it needs to be stress-tested from multiple different angles. Hence the purpose of this 12-page report is to assess whether electric vehicle cost parity could be achievable in 2025-30.

We started by breaking down the costs of EVs and ICEs, across 25 cost lines, via two granular sum-of-the-parts models of vehicle costs.

What is driving the costs of electric vehicles today? How much more expensive are they on an apples-to-apples basis? And is it really fair to call an EV simply an ‘iPad on wheels’? Answers to these questions are discussed in the first half of the report.

Electric vehicle cost parity could be achieved by deflating the different cost lines. But how much running-room is left for battery cost deflation? And if we delve into the supply chain, are Tier 1 and Tier 2 suppliers guiding towards any pricing reductions? Answers are on pages 6-8.

Could smaller electric vehicles emerge, drive down costs, and boost adoption? Or can we draw any deflationary conclusions from BYD‘s famous Seagull EV, on sale in China for the equivalent of $10-14k? We have attempted to answer these questions on pages 9-10.

How do subsidies, incentives and tariffs change the costs of electric vehicles in the developed world? And will this boost adoption from here? This topic is discussed on pages 10-11.

Our outlooks for regional EV adoption and regional oil market evolution are re-visited in light of the new analysis on page 12.

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Electric vehicles: saturation point?

Energy transition technologies are often envisaged to follow S-curves: rapidly inflecting, then reaching 100% market adoption. However, this 17-page report argues electric vehicles will more likely saturate at 15-30% of sales in 2025-30. Electric vehicle sales were already at 15% of global vehicle sales in 2023. So what would the more limited EV upside mean for energy and materials?

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Electric vehicle sales have recently endured negative news flow. Hence, we have already been forced to revise down our global EV sales forecasts, in June, by 20-25% for 2025-30. The weakness has impacted auto-makers, lithium markets and other materials, as shown on pages 2-3.

So, will EV sales start reaccelerating, or conversely, could they even flatline? The bulls in this debate will point to S-curves, arguing that EV sales are inflecting upwards. But is this really the right conceptual model for EV adoption, for the reasons explored on pages 4-5?

Affordability remains the major barrier for EV adoption in our view. Hence we have gathered data into the distributions of incomes across the developed world, and the distributions of EV costs, on pages 7-8.

Climate attitudes are another barrier for EV adoption. Last year, it was reported that 40% of Americans would not give $2 per month to avoid the worst impacts of climate change. The most relevant survey data into climate attitudes are compiled on pages 9-10.

Hence, we have attempted to model the saturation point for electric vehicles among developed world vehicle purchasers, on pages 11-13.

Market saturation for electric vehicles would have extreme implications across energy and materials markets. Some examples are given on pages 14-15.

Revisions to our numbers are finalized on pages 16-17, across electric vehicles, ICE vehicles, oil demand, the electricity demand of EVs, lithium demand, and with implications across new energies.

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There has never been more controversy over the fair values of power generation assets, which hinge on their remaining life, utilization, flexibility, power prices, rising grid volatility and CO2 credentials. This 16-page guide covers the fair value of generation assets, hidden opportunities and potential pitfalls.

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What is the fair value of a portfolio of power generation assets? This question increasingly matters, for the valuations of independent power producers, for assessing deal flow in the utility sector, for renewable energy developers, and for those looking to secure reliable power for new loads amidst grid bottlenecks.  

Hence this 16-page report is a guide to the fair value of generation assets, drawing on over 100 notes, models and data-files, published over the past five-years, and available to TSE subscription clients.

The work is informed by transaction prices for generation assets and replacement costs, but most of all by NPV calculations for onshore wind, offshore wind, solar, hydro, nuclear, gas CCGTs, gas peakers, coal, biomass and diesel gensets.

A good general ballpark for the fair value of any generation asset, in $/kW terms, is spelled out as a function of three variables on pages 4-5.

A crucial consideration is that power grid volatility is rising, which in turn affects the pricing and margins that can be achieved by different generation assets, as shown on pages 6-7.

As a result, we see rising fair values for gas peaker plants and grid-scale batteries, as quantified on pages 8-9, but looming PPA cliffs for maturing solar and wind assets, considered on pages 10-12.

Carbon credentials are another dimension which can sway the value of generation assets, especially amidst rising RECs prices, and changing regulations. Our valuation framework is on pages 13-14.

Immediacy is yet another variable that can sway the perceived value of generation assets, and could lead to unprecedently high future deal prices for low-carbon baseload assets, such as nuclear and hydro generation facilities, per pages 15-16.

The next few years will yield some fascinating deal prices for generation assets, amidst rising grid volatility and CO2 considerations. 

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What does it take to move global oil demand by 1Mbpd? This 22-page note ranks fifteen themes, based on their costs and possible impacts, to show what drives global oil demand, where risks lie for oil markets, and where opportunities are greatest to drive decarbonization. We still think global oil demand plateaus around 105Mbpd mid-late in the 2020s, before declining to 85Mbpd by 2050. But the risks now lie to the upside?

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Global oil demand will run at 103Mbpd in 2024, growing another 1Mbpd from 2023. Yet the lowest-cost and most practical roadmap to net zero would see oil use plateau around 105Mbpd in the mid-2020s, then decline to 85Mbpd by 2050.

Global oil demand forecasts: by end use, by product, by region?

There is huge hubris in these forecasts. We are assuming that after a century of growth, averaging +1Mbpd/year since 1990, oil demand will suddenly start stagnating, then declining. Are we as forecasters really able to outsmart historical precedents, especially given forecasters’ poor track records in predicting the future? (pages 2-3).

Our methodology in this report is to take fifteen of the most important themes that could sway global oil markets, then to evaluate what it would take for each theme to move global oil markets by 1Mbpd, in terms of capex, ongoing costs, oil price breakevens, resource requirements and land intensities. Thus we have written a 1-2 page snapshot for each theme, covering our favorite facts and figures (pages 4-21).

Covered themes are GDP growth, fuel economy, electric vehicles, going online, industrial efficiency, expanded recycling, wind and solar, heat pumps, corn ethanol and sugar ethanol, renewable diesel, ammonia shipping fuels, biogas to liquids, hydrogen trucks and e-fuels.

What drives global oil demand? Of the fifteen themes, we reach the conclusion that only three themes can really move oil markets by +/- 5Mbpd over the next decade. Another seven themes may have -1Mbpd impacts over the next decade. Some themes stand out as golden opportunities. Realism is needed when assessing other higher-cost options.

Subtle changes in forecasts, such as 0.5% pa faster GDP growth and a slower deployment curve for electric vehicles could see global oil demand continuing to rise, and ramping up to 110Mbpd by 2050 (page 22).

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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?