Global CO2 emissions are around 50GTpa on a fully loaded basis in 2021. Without intervention, it is likely that global CO2 emissions would surpass 80GTpa by 2050. Our decarbonization research covers opportunities to achieve an energy transition and abate CO2.
Generally, we label data-files under the ‘decarbonization’ category when they are directly about decarbonization opportunities, and when they do not fit squarely into other research categories on our website, such as wind, solar, coal-to-gas, efficiency technologies, CCS or nature-based CO2 removals.
Examples of decarbonization research include our roadmap to net zero, screens tracking the decarbonization targets of companies, or screens of companies’ purchases of nature-based CO2 removal credits.
Other examples cover the relative CO2 savings (aka CO2 abatement) that might be achieved by deploying other technologies in the energy transition. For example, an EV has 70% lower CO2 emissions than an ICE over its entire operating life-cycle.
This data-file provides an overview of the 3.5Mbpd global biofuels industry, across its main components: corn ethanol, sugarcane ethanol, vegetable oils, palm oil, waste oils (renewable diesel), cellulosic biomass, algal biofuels, biogas and landfill gas.
For each biofuel technology, we describe the production process, advantages and drawbacks; plus we quantify the market size, typical costs, CO2 intensities and yields per acre.
While biofuels can be lower carbonthan fossil fuels, they are not zero-carbon, hence continued progress is needed to improve both their economics and their process-efficiencies.
Our long-term estimateis that the total biofuels market could reach 20Mboed (chart below), however this would require another 100M acres of land and oil prices would need to rise to $125/bbl to justify this switch.
The data-file also contains an overviewof sustainable aviation fuels, summarizing the opportunity set, then estimating the costs and CO2 intensities of different options.
Navigating the energy transition in 2024 requires focusing in upon bright spots, because global energy priorities are shifting. Emerging nations are ramping coal to avoid energy shortages. Geopolitical tensions are escalating. So where are the bright spots? This 14-page note makes 10 predictions for 2024.
What is the most likely route to net zero by 2050, decarbonizing a planet of 9.5bn people, 50% higher energy demand, and abating 80GTpa of potential CO2? Net zero is achievable. But only with pragmatism. This 20-page report summarizes the best opportunities, resultant energy mix, bottlenecks for 30 commodities, and changes to our views in 2023.
This 16-page report beaks down global CO2 emissions, across six causal factors and 28 countries and regions. Global emissions rose at +0.7% pa CAGR from 2017-2022, of which +1.0% pa is population growth, +1.4% pa rising incomes, -1.4% pa efficiency gains, -0.5% renewables, 0% nuclear, +0.2% ramping back coal due to underinvestment in gas. Depressingly, progress towards net zero slowed down in the past five years. Reaching net zero requires vast acceleration in renewables, infrastructure, nuclear, gas and nature.
Biogas costs are broken down in this economic model, generating a 10% IRR off $180M/kboed capex, via a mixture of $16/mcfe gas sales, $60/ton waste disposal fees and $50/ton CO2 prices. High gas prices and landfill taxes can make biogas economical in select geographies. Although diseconomies of scale reward smaller projects?
Biogas is a mixture of 50-70% methane and 30-50% CO2, produced from the anaerobic digestion of organic matter, such as manure, sewage or crop residues, or other organic waste. Archaea notes that 72% of US renewable natural gas comes from landfills, 20% from livestock, 5% from organic waste and 3% from wastewater.
This economic model captures the costs of biogas production, informed by 20 case studies, covering yields, capex, opex, IRRs and sensitivities.
Biogas yields average around 4 mcf per ton of input material, although smaller plants may find it easier to source high-quality feedstocks, with greater quantities of volatile organic matter, and greater conversion of that matter into biogas (chart below).
The capex costs of biogas plants are also tabulated from the 20 case studies in this data-file. Costs vary. But good rules of thumb might be $200/Tpa of feedstocks. In energy industry terms, this is equivalent to around $180M/kboed, or around 6x the costs of offshore hydrocarbons, or around $2,500/kW-th, which again is around 2x higher than the per kW-e costs of solar or onshore wind.
Biogas production facilities need to earn around $35-40/mcfe of methane-equivalent production in order to generate a 10% IRR on their up-front capex. There are four main revenue streams: gas, waste disposal fees, CO2 prices or incentives, and the value of residual digestate, which can be used as fertilizer or bedding in agriculture.
Our base case biogas cost model sees a 10% IRR from a combination of $16/mcf methane, $60/ton disposal fees and a $50/ton CO2 incentive. However, $120/ton landfill taxes can take the methane-equivalent price down to as little as $2.5/mcf. Hence the economics depend on landfill taxes and gas prices in different countries.
Biogas production in Europe currently comprises around 1-2% of the total gas grid, although some studies have estimated that total biogas production could reach 10-20% of total, or around 50-100bcm pa in Europe, via a “huge scale-up”.
One interesting observation from the charts above is that unlike other economic models in our library, biogas facilities may not benefit from economies of scale. Smaller facilities seem to cost less in capex terms and achieve higher yields. This suggests an opportunity for middle-markets private equity and companies with many small facilities?
Please download the data-file to stress-test biogas production costs. We are also constructive on some of the economic opportunities in landfill gas and biochar.
How would CO2 abatement costs end up being distributed, if they matched the distribution of US incomes? Or to phrase it another way, what if all Americans hypothetically gave up precisely 3% of their household’s post-tax incomes, in order to decarbonize the country? 90% of all decarbonization would have to cost less than $80/ton. There would be a 600MTpa market for higher cost CO2 abatement at $80-135/ton (CCS?), a 60MTpa market for high cost CO2 abatement at $150-350/ton (DAC?), and a 6MTpa market for ultra-high cost abatement at $350-1,000+/ton (green hydrogen, e-fuels?).
CO2 abatement costs as a semi-liquid commodity?
Liquid commodity markets tend to have a single market price (e.g., $/bbl for oil, $/mcf for gas, $/Oz for gold), which is theoretically available to all producers, and tends to fluctuate around long-run marginal cost. Low cost producers earn excess returns selling at the market price. High cost producers may need to shut down when market prices cannot cover their variable cash costs. Very high cost producers usually do not get to develop their projects at all.
Is CO2 abatement a liquid commodity? Many readers will be familiar with our roadmap to net zero (note below), which is based on a cost curve of technologies that can decarbonize the world 3x over. We think it will be easiest to decarbonize the world by choosing as many options as possible from the lower-end of the cost curve, which yields an average CO2 abatement cost of $40/ton globally, an upper bound around $100/ton, and all of our various supply-demand models cohere with this decarbonization scenario for reaching net zero by 2050.
CO2 abatement is only a semi-liquid commodity in this roadmap. The global energy system is too complex for a ‘winner takes all’ approach to apply. Important considerations extend beyond simply cost. And there will always be a few downright lunatics who actually consider building small-scale wind turbines or drilling the bore-holes for a ground-source heat pump at their future home in Estonia, even though the CO2 abatement costs make their analytical eyes water.
Methodology: calculating the distribution of affordable CO2 abatement costs?
The purpose of this data-file is to quantify how CO2 abatement costs might end up being distributed, if they follow the income distribution in a typical, large, wealthy country such as the United States. Specifically, our data-file asks: “how would the US’s tolerable CO2 abatement costs be distributed, if every American committed precisely 3% of their household’s post-tax, per person income, to offset the nation’s CO2 emissions?”
To estimate this, we have downloaded data on US household incomes, percentile by percentile, converted into post-tax per person income, using data from the IRS, estimated the CO2 emissions in each income bracket (based on data and charts below). Then we simply calculate 3% of that post-tax per person income and divide by our estimate of CO2 emissions per capita in each income percentile (reference charts below).
Conclusions: market sizing for energy transition technologies?
20% of all US decarbonization, or 1.4 GTpa, must cost below $20/ton, if the distribution of CO2 abatement costs is to match the distribution of household incomes. This is because 20% of American households have a post-tax income per person below $10,000 per year. Generally, the lowest cost technologies in our roadmap to net zero are energy efficiency technologies, where the up-front costs of deploying these technologies are paid back by future energy savings. Many of these technologies are highly economic in their own right. As a rough conclusion, we expect over 20% of all the decarbonization will come from efficiency technologies, which matches our roadmap to net zero.
Half of all US decarbonization must cost <$45/ton, because the median American household earns $24,000 in post-tax, per person income, while the individuals in this household tend to emit 16 tons of look-through CO2 per person per year. There are still some forecasters in fantasy land (note below), thinking that the world can be decarbonized without paying for pragmatic decarbonization solutions, or rather by deploying technologies that cost several hundred dollars per ton, and would absorb over 30% of the average income of the median American. The best examples in the 4GTpa middle ground of pragmatic decarbonization technologies costing $20-80/ton of CO2 abatement include wind, solar, expanding power grids, scaling up natural gas and nature based CO2 removals.
Higher cost decarbonization technologies, costing in the range of $80-140/ton could scale up into the range of 600MTpa in the United States, if the distribution of CO2 abatement costs ends up matching the distribution of incomes, and we run up to the 99th percentile. This is an interesting number, because we think CCS and blue hydrogen are most often going to be in the range of $80-140/ton. And we have also estimated, in bottom-up analysis, that this is the kind of market size that US CCS could achieve (note below).
High cost decarbonization opportunities that cost around $150-350/ton could find a limited market of around 60MTpa (1% of total US decarbonization) if the distribution of CO2 abatement costs matches the distribution of post-tax incomes in the country. An example of a CO2 abatement technology in this approximate cost and size category might be DAC. Some buyers may be willing to pay a premium for DAC CO2 removal credits over reforestation removal credits due to higher perceived quality, especially around the dimension of CO2 permanence.
Ultra-high cost decarbonization opportunities that cost $350-1,000+/ton could find an even more limited market of around 6MTpa (0.1% of all decarbonization), if the distribution of CO2 abatement costs paid to decarbonize the United States matches the distribution of incomes. We think that green hydrogen will most likely fall in this abatement cost range, in the ‘upper 0.1%’ of CO2 abatement by cost; a kind of energy technology equivalent of the ‘upper 0.1%’ of households with a pre-tax income above $2.6M per year ($770k per household member). And indeed, there will probably be some niche deployments of green hydrogen. Some niches can also be economically interesting. And some rough maths is that 6MTpa of CO2 abatement from green hydrogen might require 1MTpa of hydrogen, absorbing 50 TWH of renewable electricity and supporting 18GW of electrolysers by 2050, while displacing 100 bcf of natural gas (0.3 bcfd, versus today’s 100bcfd US gas market). Whether these are big numbers or small numbers depends entirely on your mindset.
This 14-page note explores an alternative framework for energy transition: what if the fantasy of the perfect consistently de-rails good pragmatic progress; then the world back-slides to high-carbon energy amidst a cascade of crises? We need to explore this scenario, as it yields very different outcomes, winners and losers compared with our roadmap to net zero.
The universe of energy transition stocks seems small at first. 50 clean tech companies have $1trn in combined value, less than 1% of all global equities. But decarbonizing the world is insatiable. Consuming ever more sectors. In our attempt to map out all of the moving pieces, we are now following over $15trn of market cap across new energies, (clean) conventional energy, utilities, capital goods, mining, materials, energy services, semiconductors.
This data-file is a screen of companies that reduce gas flaring emissions, either by avoiding routine flaring directly, or by reducing the ESG impacts of unavoidable flaring. The landscape is broad, ranging from large, listed and diversified oil service companies with $30bn market cap to small private analytics companies with <$10M pa of revenues.
Our screen explores a dozen companies that reduce gas flaring and can help to mitigate flaring; whether they are public or private, their size, headcount, focus, revenues, valuation, and an overview of their technology. But this is just a sample of names, to illustrate the breadth of the theme.
Breadth and the giant furnace model. There is a dangerous temptation to assume that oil industry flaring is simple. It is vastly complex. Flaring rate by country range from effectively nil in industry-leading Norway and Saudi Arabia through to 0.7 mcf/bbl in the highest-flaring producing countries. And even where flaring does occur, beware assuming there is some kind of giant furnace in the desert of Texas where the shale oil industry ‘chooses to burn off waste gases’.
The reality is borne out by this screen. Avoiding flaring requires oilfield service equipment to separate out gas from produced oil. Moving it away from the well site then requires compressors, pipelines, small-scale LNG, CNG or using gas in basin, e.g., for dual-fuel rigs or frac services or in-basin power generation. Sometimes it is not possible to separate the gas, and fluids must be moved by multi-phase pumps. Sometimes wells are flowed back before gas infrastructure is available. Sometimes, despite extensive separation, gas still flashes off in storage tanks. Sometimes flaring is unavoidable, and the goal is simply to ensure all methane is effectively destroyed in the flare, and not leaked away.
The emissions tab contains a similar calculator for the CO2 intensity of flaring, depending on the gas-oil-ratio, percent of gas that is flared, combustion efficiency and timeframe over which methane emissions are considered. We believe that poorly-managed flaring operations from some oil production sites around the world will emit more CO2 than burning the resultant oil itself, due to methane slip. Whereas emissions from flaring are negligible for high-quality producers.
This 17-page report revisits our roadmap for the world to reach ‘net zero’ by 2050, after integrating over 1,000 pieces of research from 2019 through 2022. Our updated roadmap includes large upgrades for renewables and energy efficiency; less reliance on new energies breakthroughs; but most of all, simple, pragmatic progress is needed as bottlenecks and shortages loom.
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