This data-file captures the economics of gas-to-liquids, including the formation of syngas in an auto-thermal reformer, then the subsequent upgrading into liquids via the Fischer-Tropsch reaction.
Our base case is that $100/bbl realizations are required for a 10% IRR. You can stress-test the economics as a function of gas prices, capex costs, thermal efficiencies, carbon intensity, CO2 prices and other operating costs.
Our inputs for each of the categories above are substantiated by collating data-points from past projects and technical papers. Finally, our notes and review of GTL patents are outlined in the final tabs.
Which refiners are least CO2 intensive, and which refiners are most CO2 intensive? This spreadsheet answers the question, by aggregating data from 130 US refineries, based on EPA regulatory disclosures.
The full database contains a granular breakdown, facility-by-facility, showing each refinery, its owner, its capacity, throughput, utilisation rate and CO2 emissions across six categories: combustion, refining, hydrogen, CoGen, methane emissions and NOx (chart below).
Assessed companies include Aramco, BP, Chevron, Citgo, Delek, ExxonMobil, Koch, Hollyfrontier, Marathon, Phillips66, PBF, Shell and Valero.
Nature-based solutions are among the most effective ways to abate CO2. Forest offsets will cost $2-50/ton, decarboning liquid fuels for <$0.5/gallon and natural gas for <$1/mcf (chart below).
The data-file tabulates hundreds of data-points from technical papers and industry reports on different tree and grass types. It covers their growing conditions, survival rates, lifespans, rates of CO2 absorption (per tree and per acre) and their water requirements (examples below).
This data file tabulates the acreage footprints and peak worker counts at c20 recent LNG projects. It is interesting how these variables are likely to change over time, to lower costs and due to COVID.
International LNG occupies c50-acres per MTpa and 1,000 peak workers per MTpa of capacity. This means that largest facilities can have over 20,000 workers on site at any one time, which will be challenging amidst COVID.
US LNG projects have been smaller, at c30-acres per MTpa, as high-quality input gas requires less pre-processing; and worker counts are as much as 4x lower, due to phased, modular construction designs (see below).
FLNG is c20x more compact than typical international projects but and has the highest density of workers. Modules which typically have large exclusion zones are congested. This will require extremely cautious operation. It could impact economics, through higher costs and lower up-times.
In principle, smaller plants should achieve cost advantages over larger plants. To reap these benefits, we are excited by novel “liquefaction” technologies, which are also tabulated in the file.
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.
Shell is revolutionizing LNG project design, based on reviewing 40 of the company’s gas-focused patents from 2019. The innovations can lower LNG facilities’ capex by 70% and opex by 50%; conferring a $4bn NPV and 4% IRR advantage over industry standard greenfields. Smaller-scale LNG, modular LNG and highly digitized facilities are particularly abetted. This note reviews Shell’s operational improvements, revolutionary greenfield concepts, and their economic consequences.
CO2 and methane intensities are tabulated for 300 distinct company positions across 9 distinct basins in this data-file. Using the data, we can aggregate the total CO2 in (kg/boe) and methane leakage rates (as a percent of natural gas production) across the US’s different basins.
Covered basins include the Permian, Bakken, Eagle Ford, Marcellus/Utica, Alaska, GoM, Powder River, San Juan, Anadarko basin and DJ basin (chart above).
It is possible to rank the best companies in each basin, using the granular data, to identify industry leaders and laggards (chart below).
This model calculates the costs of post-combustion carbon capture at a world-scale refinery, using today’s commercially available CCS technologies. The aim is to see whether the process could be economically competitive, as oil refineries emit c1bn tons of CO2 per annum.
Carbon capture costs vary unit-by-unit, as a function of the unit’s size and the CO2-concentration in its flue gas. Hence we estimate that c10-20% of refinery emissions can be eliminated for $XX/ton, the “middle 50%” will cost c$XX-XX/ton, while the final 20% will cost $XX-XX/ton. Calculations can be flexed in the model, using alternative input assumptions.
Our estimates are informed by an excellent technical paper from Shell, which is also summarised.
This data-file tabulates details of the c35 companies commercialising catalysts for the refining industry. Improved catalysts are aimed at better yields, efficiencies and energy intensities. This is the leading route we can find to lower refining sector CO2 emissions.
In particular, we find five early-stage companies are aiming to commercialise next-generation refining catalysts.
We also quantify which Majors have recently filed the most patents to improve downstream catalysts.
If you would like us to expand the data-file, or provide further details on any specific companies, then please let us know…
We have modeled out simple economics for Northern Lights, the most elaborate carbon capture and storage (CCS) scheme ever proposed by the energy industry (Equinor, Shell, TOTAL).
The project involves capturing industrial CO2, liquefying it, transporting it in ships, receiving it onshore in Norway, piping it 110km offshore, then injecting it 3,000m below the seabed. Phase 1 will likely sequester 1.3-1.5MTpa, with potential expansion to 5MTpa.
Our conclusion is that Phase 1 will be expensive. However, much of the infrastructure “scales”. So phase 2 could cost 35% less, bringing the “carbon storage” component to below Europe’s carbon price. This could be promising if combined with next-generation carbon separation or decarbonised gas technologies, to lower the “carbon capture” component.
Our economic estimates can be flexed in the ‘simple model’ tab. Underlying cost calculations are substantiated in the ‘Notes’ tab.