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 June-2022, it contains 260 differentiated views on 140 public companies.
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.
This data-file looks through 17 major nuclear plants in Japan with 45GW of operable capacity, covering the key parameters and re-start news on each facility.
In 2010, before the Fukushima crisis, Japan produced 292 TWH of nuclear electricity, which would have required about 40MTpa of LNG imports if it had all been generated by gas instead.
With all its nuclear plants shut down in 2011-12, LNG imports jumped by around 20MTpa, while the remaining shortfall was covered by ramping oil-fired power back upwards by c600kbpd.
In early-2022, we estimate there is 30TWH of upside from ramping up facilities that have partially restarted (saving 5MTpa of LNG). There is another 100TWH of upside from ramping relatively safe but idle facilities (saving 15MTpa of LNG). There is another 100TWH of upside from ramping more controversial facilities, where debates still linger over their integrity amidst the tail-risk of a direct hit from a massive earthquake (another 15MTpa of LNG), although these facilities could in principle re-start temporarily amidst a war or energy crisis.
Total global nuclear generation is around 2,800 TWH pa, so this scenario also presents meaningful uranium upside.
This data-file captures the economics for a typical LNG regas facility. We estimate that a fixed plant with 75-80% utilization requires a spread near to $0.8/mcf on its gas imports, in order to earn a 10% IRR.
However, infrastructure-like investments, such as regas facilities typically get financed off lower return expectations, and $0.6/mcf is sufficient for a 6% IRR.
The main input is cost, which we have appraised based on past projects, company disclosures and technical papers (chart below).
Most interestingfor the 2020s is the asymmetric upside that could result from extreme gas market tightness. In times of weak pricing, downside is capped, as you can idle the facility. But recent history shows that during times of gas shortages, gas prices effectively have uncapped upside, and this can easily add 3-10% to full-cycle IRRs.
Our LNG supply model looks project-by-project, across 125 LNG facilities: including c40 mature plants, c12 under development, c20 in design and c25 under discussion.
Our base case supply estimatescome from “risking” the supply associated with each of these projects (chart below). Use of LNG should rise at over 8% per year to drive the energy transition and displace coal, but there are only enough developments underway for a 4-5% CAGR, as COVID has deferred 70MTpa of start-ups.
The outlook depends on the path. The 2030 supply outlook can vary by c300MTpa, when comparing all reasonably possible supply (top chart) against the firm supply-growth that looks all but locked (bottom chart). Qatar and select US projects are the most exciting new supply sources.
The greatest opportunities in LNGare therefore to create new demand and to advance competitive projects when others are cannot. To see which projects we think will progress, please download the data-file.
This model estimates European gas demand in the 2020s, as a function of a dozen input assumptions, which you can flex. They include: renewables’ growth, the rise of electric vehicles, the rise of heat pumps, the phase out of coal and nuclear, industrial activity, efficiency gains, LNG-transport fuel and hydrogen.
Our conclusionis that European gas demand would be likely grow at its fastest pace since the early-2000s, largely driven by the electricity sector, if there were sufficient supplies. However, as indigenous production wanes, there is a risk of persistent gas shortages, and prices will need to rise to the point of demand destruction.
The data-file also contains granular data, decomposing gas demand across 8 major categories, plus 13 industrial segments, going back to 1990 (albeit some of the latest data-points are lagged); as well as 15 different supply sources, with monthly data going back a decade (chart below).
Please download the modelto run your own scenarios…
The purpose of this data-file is to model the economics of shipping large cryogenic cargoes, such as LNG or liquefied CO2 in larger tankers. In each case, we break down the costs and day-rates needed to earn 10% IRRs, including capex, opex, fuel, maintenance and port fees.
Shipping an LNG cargo costs $1-3/mcf, while the most important input variable is the distance from source to destination.
Shipping a CO2 cargo costs $5-50/ton, while again the most important input variable is transport distance. Although in the CO2 case, using a low-carbon e-fuel (e.g,. ammonia, green methanol) approximately doubles total cost.
Input variables and assumptions are broken down on the backup tabs (e.g., below). Please download the data-file to stress test these inputs.
A vast new up-cycle for LNG is in the offing, to meet energy transition goals, by displacing coal and improving industrial efficiency. 2024-25 LNG markets could by 100MTpa under-supplied, taking prices above $9/mcf. But at the same time, emerging technologies are re-shaping the industry, so well-run greenfield projects may resist the cost over-runs that marred the last cycle. This 18-page note outlines who might benefit and how.
This data-file tracks patent progress into LNG liquefaction plants from 2020, by reviewing forty recent patent filings from leading companies in the industry (integrated oil companies and service providers).
We reach three key conclusions: (1) LNG capex costs should not be overly fixated upon, as they can come at the expense of higher opex and emissions intensities. (2) The next generation of modular plants offer a step-change from the first generation. (3) And new process technologies are helping to improve efficiency across different LNG process units and their fabrication.
The full data-filespells out our conclusions, with details on each of the underlying patents, a review of companies filing LNG patents in 2020.
This model captures the economics for a typical LNG liquefaction project, breaking down IRRs and NPVs as a function of key input-variables.
The InputsOutputs taballows you to flex key variables such as: LNG sales price, Capex/tpa, Opex/mcf, Utilization, Thermal Efficiency, LNG shipping distance, LNG tanker rates, and liquids cuts. A detailed capex breakdown is also provided (below).
A base LNG case project is likely to earn a c10% real, unlevered IRR at $7.5/mcf. The economics are most sensitive to gas pricing and capex; and somewhat less sensitive to the other variables.
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