European shale: an overview?

Europe has 15 TCM of technically recoverable shale gas resources according to an assessment from the EIA in 2013, which remains the best overview, almost ten years later. This data-file simply aims to provide a helpful overview of the different countries’ rocks and above-ground challenges, tabulating the main formations, TOCs, depths, thicknesses, clay contents and exploration history.

Our first conclusion is how much the world has changed since the early days of European shale exploration, a decade ago, including ten years’ proof that US shale has not caused an entire continent to die a mysterious death. Indeed, US industry, has seemed to gain a mysterious new life. While Europe is now so short of energy that we may need to scale our industry back at a time when we would rather be re-shoring strategic supply chains).

While Europe is  now trying to import vast amounts of US shale gas to Europe as LNG (note here), another complementary option, we think is to re-visit the possibilities of European shale; especially in Eastern Europe, which has large, high-quality shale resources, high continued reliance on coal (Poland, Bulgaria) and a growing desire to avoid Russian reliance.

Ukraine has the best shale resources in all of Europe: 4.5% TOC, 1.15% maturity (gas window), low clay and moderate over-pressure. Shell tested these rocks and obtained results good enough to sign a $10bn development agreement that could ramp output up to 20bcm per year. At the time, Ukrainian politicians stated the country could ultimately run a “gas surplus”. This was 2013. Just before Russia’s first invasion. And this Continent-leading Dniepr-Donets shale resource lies in the East of the country, bounded by Kharkiv and Donetsk, near to the current fighting. Which may or may not be a coincidence.

It is difficult to know to what extent Russia fomented broader opposition to European shale. Some of the hysteria seems almost farcical in retrospect. In Romania, in 2013, as Chevron signed an exploration contract, one town saw the largest protest in its entire history (16% of the population), as 8,000 people took to the streets with signs reading “Don’t kill our children”.

(We humbly submit that if you are writing this on a placard, you might not understand what shale gas involves. The simple goal is to produce energy safely, with 50-60% lower carbon than coal (note here) at a marginal cost of $1.5-2/mcf (model here)).

Other countries with good potential, held back only by sentiment are Romania, Germany, UK, Bulgaria and Spain. We remain more cautious on the potential in Sweden and Denmark (the Alum has expelled its gas), Netherlands (population density), Poland (clay makes the rock harder to fracture) and France (continuing to rely on nuclear is its best low-carbon option).

Wind and solar: costs of grid inter-connection?

What are the costs of inter-connecting a utility-scale wind or solar project into the power grid, via a spur line, grid tie-in or feeder?

This data-file assesses twenty case studies of renewables assets in North America, based on published inter-connection documents.

Costs are highly variable. But a good baseline is to expect $100-300/kW of grid inter-connection costs, or $3-10/kW-km, over a 10-70 km typical distance (which includes the length of downstream lines that must be upgraded). Larger and higher voltage projects tend to have lower tie-in costs.

What is most surprising is how vastly the ranges can vary. The lowest-cost tie-in was $25/kW, tying in a solar asset to a 230kV power line with spare capacity that is a mere 1-mile away. Whereas the highest-cost tie-in was $1,250/kW (i.e., more than the 40MW solar project itself!) where the asset owner was asked to contribute an eye-watering c$50M to cover the costs of upgrading 500km of high-voltage transmission lines downstream of the inter-connection point.

High voltage transmission cables: power parameters?

This data-file aggregates technical parameters of high-voltage power lines, including some of the largest and highest-voltage UHV AC and HV DC lines built in the world, which connect disparate regions of China.

The average of these projects transmits 6.5GW, at 800-1,000kV and 4,000 Amps, over a distance of 1,500 km.

Towers. Every 500 meters, there is a 70m tall tower, which weighs 80 tons.

Cables. Each tower supports 2-3 cable bundles, comprising 6-8 sub-conductors. Each of these sub-conductors is a 750mm2 and 2.5 tons/km cable of 40-80 aluminium sub-wires.

The total mass of the power lines is about 200 tons per km (i.e., about 50% lower than the high powered lines in the West).

Line losses are around 2-3% per 1,000km and total project costs are likely below $3M/mile (again, both are plausibly around 50% lower than Western examples today).

Back-up tabs contain calculations around I2R losses, corona losses and reactive power consumption.

California curtailment: key numbers from 2021?

This data-file tracks curtailment of wind and solar assets in Califonia, in order to assess the opportunity of integrating more renewables. c25% of Califonia’s total grid demand in 2021 was met by wind and solar energy generated in the State.

On average, 0.4% of the wind and 4% of the gross solar generation were curtailed throughout the year. But the data are highly variable.

Curtailment was highest in March, when 1% of the wind and 12% of the gross solar generation were curtailed. There were even five days in the year where over 30% of the solar was curtailed. On the other hand, August was the ‘best’ month, where only 0.3% of the wind and 0.9% of the solar generation was curtailed.

The uneven distribution is somewhat unhelpful for the economics of grid-scale batteries. We estimate that 10% of the curtailment could be avoided by the ‘best’ battery installations, which get to charge-discharge 360 days per year. Another 7% could be avoided by the next bext battery installations, which get to charge-discharge c300 days per year. And so on.

However, the final 50% of the curtailment would require resorting to low utilization batteries, which only get to charge-discharge on fewer than 70 days per year, raising their costs, lowering their EROEI.

Hydrogen: what GWP and climate impacts?

This data-file aggregates technical data into the Global Warming Potential (GWP) of hydrogen, in order to draw conclusions for decision-makers in the energy transition.

(1) Hydrogen is not a direct GWP, as H-H bonds in the hydrogen molecule do not directly absorb infrared radiation, indeed nor do other symmetrical diatomic molecules like N2 or O2 (no permanent dipole moments).

(2) But hydrogen is an indirect GWP, as it breaks down in the atmosphere over 1-2 years, and its reaction products increase the GWP impacts of other GHGs, such as methane, tropospheric ozone and stratospheric water vapor.

(3) The best estimates we have tabulated in our data-file give a 100-year GWP for hydrogen that is 11x stronger than CO2 and for methane that is 34x stronger than CO2 (please download the data-file for the details).

(4) Concerns? In other words, if you are worried about the climate impacts of leaking 0.6 – 3.5% methane across global gas value chains, the climate impacts are effectively the same for leaking 2 – 10% hydrogen across a hydrogen value chain.

(5) 3x higher hydrogen leakage rates are not an unjustified concern, because the radius of an H2 molecule is about 3x smaller than the radius of a CH4 molecule, and the boiling point is -253C (versus -162C for methane) resulting in more boil-off, and thus upper estimates for H2 leakage rates as high as 20% have crossed our screen.

(6) The hydrogen industry might adapt: by monitoring and mitigating its leakage rates, much like the gas industry needs to do; and by preferring shorter and simpler value chains, direct substitution for pre-existing hydrogen in industry; or transporting hydrogen in carrier molecules (toluene, ammonia, electrofuels are less likely to result in hydrogen emissions, even if they are more expensive).

(7) CH4 Condemnation? Over 50% of the GWP impacts of hydrogen arise because hydrogen mops up hydroxyl radicals, which in turn, prevents these hydroxyl radicals from breaking down methane molecules. Thus the 100-year warming impacts of methane are exacerbated. In other words, the climate impacts of atmospheric hydrogen directly link to the atmospheric impacts of methane. The more worried you are about one, then logically, the more worried you should be about the other. Hydrogen and methane are “in it together” when it comes to GWP.

(8) CH4 Collaboration. Atmospheric methane is around 1,900 ppb, 160% above pre-industrial levels. Every year, about 40% of the world’s methane emissions comes from natural sources like wetlands, 25% from agriculture, cow burps and rice, 25% from coal, oil and gas and c10% from waste landfills. H2’s GWP can be improved by encouraging better methane management in all of these other categories.

Socially responsible ETFs: portfolio summary?

socially responsible ETFs

This data-file evaluates the holdings of 20 socially responsible ETFs with $150bn of assets, as of 2022. The average fund marketing itself as an “ESG” or “Socially Responsible” has c$10bn of AUM, a 0.3% expense ratio and 500 holdings, of which the ‘top ten’ comprise around 30% on average.

However, is this “socially responsible” or simply underweight energy (which comprises 1.2% of these funds versus 4.5% in the MSCI ACWI), underweight utilities (1.3% of the funds versus 4% of the ACWI) and underweight basic materials (3.4% of the funds, c4-5% of the ACWI)?

On the other hand, the average of these ETFs shares six out of its top ten holdings with the ACWI, including a 6% average allocation to Microsoft, 3.3% Google, 3.3% Apple, 3% Tesla, 2% Nvidia, and other common holdings included J&J, United Health, JPMorgan, Home Depot, Coca Cola.

More constructively, the file also includes a handful of “clean energy” ETFs, whose holdings are a lot more interesting to us. The average of these funds is 15% energy, 20% utilities, and 30% manufacturing of energy and utility inputs. However, this universe is smaller, with the average fund only $1.5bn in assets and more concentrated across an average of 75 holdings.

Recent Commentary: please see our article here. Our own view is that energy transition is not helped by removing capital, but rather, by supporting public companies and private companies that can drive the energy transition.

Ionic radius: comparing cation chemistry?

ionic radius

Ionic radius measures the width of ions, in pico-meters (one billionth of a millimeter, one trillionth of a meter), or in angstroms (100 pico-meters). The average across a range of cations is around 100 pico-meters, or 1 angstrom.

But surprisingly, ionic radius is only about 40% correlated with atomic mass. Yes, H+ ions are smallest, at 0.0008 pico-meters, and ionic radius rises as you move ‘upwards’ within each group of the Periodic Table.

But on the other hand, lithium ions (atomic mass = 7) are similar to most transition metal ions (atomic mass 50 – 60), and about 40% larger than aluminium 3+ (atomic mass = 27).

The first reason is that when an atom loses electrons, the remaining electrons become more attracted to the nuclei, and thus cluster in more tightly in 3+ ions than in 2+ ions, which in turn cluster more tightly than 1+ ions.

The relationship is also non-linear for larger atoms, as the added width of wider electron shells is counteracted by adding more protons to the nucleus and thus creating a stronger positive charge that acts on all electrons.

Strictly, for fans of advanced chemistry, ionic radius varies: Ions in a high-spin state will be larger than the same ion in a low-spin state, and ions in solution may behave as though they are even wider based on how strongly and closely they attract a precise number of solvent molecules.

The data-file simply contains the data-behind the chart, in case you wish to have the exact numbers in a useful spreadsheet, or re-format the charts.

Recent commentary: please see our article here. This also informs our outlook on novel battery chemistries, such as CATL’s.

Global wood production: supply by country by year?

This data-file quantifies the global wood harvest, county-by-country, category-by-category, back to 1960, using granular data from the FAO. About 4,000 m3 of wood are harvested per year (2GTpa by mass).

The split is that 50% is used as fuel, 20% as paper/pulp and 30% as longer-lasting materials which may help remove CO2 from atmospheric circulation.

It varies greatly by economic development levels. Africa and India use 90% of their wood as fuel. The US and Europe use 20%. As Korea industrialized, wood use as fuel fell from 70% in 1960 to 7% in 2020.

Overall, wood energy has declined from 11% of the world’s primary energy mix in 1960 to c4% today. However, it remains stubbornly high in less developed countries (e.g., 30% in Africa, data below).

Deforestation remains the largest source of CO2 emissions globally, and the data suggest shortages of oil, gas and coal could exacerbate this ecological disaster. If coal, oil and gas prices all treble, then by extension, the relative value of wood-based fuels approximately trebles too.

Global LNG: offtake contracts and spot market development?

This data-base tabulates the details of over 300 offtake contracts across the LNG industry, tracking buyers, sellers, facilities, contract durations and destination flexibility. And by extension, this shows what portion of the market was traded “spot”.

Back in the year 2000, the LNG market was just 100MTpa, c90% of the market was traded on long-term contractions with >10-years’ duration, and the weighted average cargo was on a 22-year contract.

By 2021, the LNG market had almost quadrupled to over 370MTpa. c55% is still sold on >10-year contracts. Conversely, c45% was traded on a short-term basis, of which c20pp were portfolio cargoes, c3% were sold on 1-10 year contracts, c1% was imported on a contract then re-exported, and c20pp was totally uncontracted and sold on a spot basis.

What has not changed is that facilities still tend to sell their initial output on >15-year long-term contracts, to de-risk their financing. Full data on individual contracts, which can be added by country or supplier, are given in the data-file.

Energy development times: first consideration to full production?

This data-file assesses the development times of different energy resources, from their first consideration, through permitting, up to final investment decision (FID), across construction, and ultimately as they reach nameplate capacity.

Full cycle development times tend to average c4-years for large solar projects, 6-years for large offshore wind, 7-years for new pipelines, 7-years for new oil and gas projects, 9-years for new LNG plants and 13-years for new nuclear plants. There is a spread within each category.

As a rough split, these timings break down as 40% planning, 50% construction and 10% ramp-up/commissioning. The best projects in each category are often around 50% faster than the average.

Full details are given for each of the 35 projects in the data-file, in order to stress-test our ability to cure energy shortages by ramping new projects.

Copyright: Thunder Said Energy, 2022.