This data-file compiles all of our insights into publicly listed companies and their edge in the energy transition: commercialising economic technologies that advance the world towards ‘net zero’ CO2 by 2050.
Each insight is a differentiated conclusion, derived from a specific piece of research, data-analysis or modelling on the TSE web portal; summarized alongside links to our work. Next, the data-file ranks each insight according to its economic implications, technical readiness, its ability to accelerate the energy transition and the edge it confers on the company in question.
Each company can then be assessed by adding up the number of differentiated insights that feature in our work, and the average ‘score’ of each insight. The file is intended as a summary of our differentiated views on each company.
The screen is updated monthly. At the latest update, in May-2022, it contains 260 differentiated views on 140 public companies.
This large data-file tracks activity, 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.
This model contains our live, basin-by-basin shale forecasts. 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.
For 2022, the key challenge is stepping up activity levels, as the rig count must rise +60% YoY to keep early-2020s oil markets sufficiently supplied. Conversely, in 2021, production surpassed our expectations due to an unprecedented rate of DUC drawdowns, while well productivity was also stronger-than-feared.
Our longer-term numbers hinge on the productivity gainsdescribed in our thematic 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 shale gas play, 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.
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 analysisis 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.
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 conclusionis 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 analysisis 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.
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.
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.
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.
This database tabulates almost 300 venture investmentsmade by 9 of the leading Oil Majors, as the energy industry advances and transitions.
The largest portionof 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 capabilitiesin 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 databaseshows 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.
What are the top technologies to transform the global energy industry and the world? This data-file summarizes where we have conducted differentiated analysis, across c100 technologies (and counting).
For each technology, we summarize the opportunity in two-lines. Then we score its economic impact, its technical maturity (TRL), and the depth of our work to-date. The output is a ranking of the top technologies, by category; and a “cost curve” for the total costs to decarbonize global energy.
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