European shale: an overview?

Overview of European shale

Overview of European shale. 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).

To read more about our overview of European shale, please see our article here.

Marcellus shale: well by well production database?

Marcellus well productivity data

Marcellus well productivity data. This large data-file tracks productivity, well-by-well, across c11,000 wells in the Pennsylvania Marcellus, month-by-month, from 2015-2021.

For each operator, we have tabulated production, well stock, activity levels, average well production, IP rates.

Activity levels have slowed by one-third over time, with a peak of 850 wells drilled in 2018, slowing to 570 wells in 2021.

What has enabled activity to slow down is the improvement in well productivity. Average IP rates across the basin have risen at a 16% pa CAGR, from around 5mmcfd in 2015 to 15mmcfd in the second half of 2021.

First tier operators are clearly visible in the data-file. They have come to dominate as the basin has consolidated, while they also achieve higher IP rates and have been able to do more with less.

Our top five conclusions from the Marcellus well productivity data are highlighted in the article here. For a compendium of all of our shale research, please see here.

US shale production forecasts by basin?

US shale production forecasts by basin

This model sets out our US shale production forecasts by basin. It covers the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rates, well productivity and type curves. Thus, we derive production and financial expectations.

Production. At the start of 2022, we hoped the big three US shale basins would surpass 10.0 Mbpd of liquids production by Sep-22. The latest estimate is 9.2Mbpd. A 0.8Mbpd disappointment.

Activity is the main reason. At the start of 2022, we hoped the oil rig count in these three basins would end October at 520 units, up 3.5x from the troughs of 2020. We only have about 460.

Well productivity cannot be faulted. We thought the average shale well would be IP-ing at 0.81 kbpd. The average has come in at 0.90kbpd. All three basins beat our forecasts. Bakken most so.

DUC drawdowns cannot continue forever. We anticipated 1.03 wells might get completed for every 1 well drilled in 2022. The YTD ratio is 1.11x. At 2,200, DUC count is now at its lowest since 2013.

Most strikingly, we now see 2025 shale production at 15Mbpd, 10Mbpd below the high potential seen in 2018-19, due to the whipsawing effects of COVID, and hesitancy over long-term investment.

This might support expectations for a “weird recession” in 2022-24, where economic activity is weak, but traditionally cyclical commodity prices de-couple, to incentivize needed investment?

Our longer-term numbers hinge on the productivity gains described in our thematic shale research. Shale productivity trebled from 2012-2018. We think it can rise another 45% by 2025, unlocking 15Mbpd of liquid shale production. However productivity could disappoint mildly in 2022 as the industry ramps activity levels back post-COVID.

We have also modeled the Marcellus and Haynesville shale gas plays, using the same framework, in a further tab of the data-file. Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion here, with 20-50 additional rigs.

Please download the data-file to stress-test our US shale production forecasts by basin.

US shale gas: the economics?

Economics of US Marcellus shale gas production

This data-file breaks down the economics of US shale gas, in order to calculate the NPVs, IRRs and gas price breakevens of future drilling in major US shale basins (predominantly the Marcellus).

Underlying the analysis is a granular model of capex costs, broken down across 18 components. Our base case conclusion is that a $2/mcf hub pricing is required for a 10% IRR on a $7.2M shale gas well with 1.8kboed IP30 production.

Economics are sensitive. There is a perception the US has an infinite supply of gas at $2/mcf, but rising hurdle rates and regulatory risk may require higher prices. For a similar model of shale oil, please see our model here.

Shale productivity: snakes and ladders?

Shale Productivity Snakes and Ladders

Unprecedented high-grading is now occurring in the US shale industry, amidst challenging industry conditions. This means 2020-21 production surprising to the upside, and we raise our forecasts +0.7 and +0.9Mbpd respectively. Conversely, when shale activity recovers, productivity could disappoint, and we lower our 2022+ forecasts by 0.2-0.9 Mbpd. This 7-page note explores the causes and consequences of this whipsaw effect.

US shale: the economics?

Detailed breakdown of US shale economics and costs

This data-model breaks down the economics of US shale, in order to calculate NPVs, IRRs and oil price break-evens of future drilling in major US basins (predominantly the Permian, but also Bakken and Eagle Ford).

Our base case conclusion is that a $40/bbl oil price is required for a 10% IRR on a $7.0M shale well with 1.0 kboed of IP30 production. Break-evens mostly vary within a range of $35-50/bbl. They are most sensitive to productivity, which can genuinely unlock triple-digit IRRs, even at $40/bbl.

Underlying the analysis is a granular model of capex costs, broken down across 18 components (chart below). Costs are calculated off of input variables such as rig rates, frac crew costs, diesel prices, sand prices, tubular steel prices, cement prices and other more niche services.

Stress-testing the model. You can flex input assumptions in the ‘NPV’ and ‘CostBuildUp’ tabs of the model, in order to assess economic consequences. For a similar model of shale gas, please see our model here.

US shale sand mines: simple economics?

Economic model of U shale sand production

This model is a very simple breakdown of economics for in-basin sand production, around the US shale industry. We estimate the price that must be charged at the mine gate for a typical facility to make a 10% return.

The model can also be used to quantify the potential savings from shifting from dry sand to wet sand, estimated at c25% of total costs.

US shale: our outlook in the energy transition?

US shale outlook in the Energy Transition

This presentation covers our outlook for the US shale industry in the energy transition, and was presented at a recent investor conference.

The importance of shale oil supplies in a fully decarbonized energy system is contextualized on pages 1-7. Production must grow by a vast 2.6Mbpd in 2022-25 to keep oil markets well supplied, even as oil demand plateaus. Otherwise, devastating oil shortages may de-rail the transition.

This requires a 5% CAGR in shale productivity. We argue in favor of future productivity growth, based on the evidence from 950 technical papers, which we have reviewed, on pages 8-12.

But can the industry attract capital? This now hinges upon carbon credentials. Laggards will have >25kg/boe of upstream CO2 while leaders have the opportunity to be CO2-neutral. The division (and the  prize) is outlined on pages 13-19.

US Shale: the second coming?

Future US shale productivity

Future US shale productivity can still rise at a 5% CAGR to 2025, based on evaluating 300 technical papers from 2020. The latest improvements are discussed in this 12-page note, and may spark more productivity gains than any prior year. Thus unconventionals could grow by 2.6Mbpd per annum from 2022-25 to quench deeply under-supplied oil markets. But hurdles remain. The leading technologies are also becoming concentrated in the hands of fewer operators and an emerging group of oil services.

Ventures for an Energy Transition?

Oil Major Venture Investments

This database tabulates almost 300 venture investments made by 9 of the leading Oil Majors, as the energy industry advances and transitions.

The largest portion of activity is now aimed at incubating New Energy technologies (c50% of the investments), as might be expected. Conversely, when we first created the data-file, in early-2019, the lion’s share of historical investments were in upstream technologies (c40% of the total). The investments are also highly digital (c40% of the total).

Four Oil Majors are incubating capabilities in new energies, as the energy system evolves. We are impressed by the opportunities they have accessed. Venturing is likely the right model to create most value in this fast-evolving space.

The full database shows which topic areas are most actively targeted by the Majors’ venturing, broken down across 25 sub-categories, including by company. We also chart which companies have gained stakes in the most interesting start-ups.

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