This simple, illustrative model for an LNG project’s economics, facilitates stress-testing of economic assumptions, and their impact on IRRs and NPVs.
The InputsOutputs tab allows 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 base LNG case project is likely to earn a c7% real, unlevered IRR. The economics are most sensitive to gas pricing and capex; and somewhat less sensitive to the other variables.
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 phase out of coal and nuclear, industrial activity, efficiency gains and LNG-transport fuel.
Our conclusion is that European gas demand will likely grow at its fastest pace since the early-2000s, largely driven by the electricity sector.
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).
Please download the model to run your own scenarios…
This data-file captures 65 carbon capture and storage (CCS) facilities around the world, of which c30 are currently running, with capacity to sequester 40MTpa of CO2. Capacity should rise 2.5x by 2030.
As costs deflate, CCS is expanding to more countries, more industries and away from EOR towards dedicated geological storage (charts above).
The full data-file includes each facility, its location, involved companies, construction status, volumes (MTpa), CCS process, industrial source of CO2, start-up, storage type, capex ($M where available), capex cost ($/ton where available) and 2-3 lines of notes per facility.
This data-file tabulates the methane emissions from downstream gas distribution across 160 US gas networks, which cover 1.1M miles of mains, 61M metered customers and >90% of the country’s retail gas demand.
Downstream US methane leakages average 0.2% by volume, explaining 5.7kg/boe of emissions. Two thirds of these leaks can be attributed to gas mains. Leakages are correlated with the share of sales to smaller customers. And state-owned utilities appear to have 2x higher leakage rates the public companies.
US gas utilities’ performance is screened to assess c80 distinct companies, including: Altagas, Atmos, Centerpoint, CMS, Dominion, DTE, Duke, Edison, National Grid, PG&E, Sempra, Southern Co, Spire, UGI, WEC & Xcel.
This data-file screens the methods available to monitor for methane emissions. Notes and metrics are tabulated for Method 21, Optical Gas Imaging, fixed sensors, ground labs, aircrafts, drones and satellites; including advances at the cutting edge of each method.
Emerging screening methods, such as drones and trucks are also scored, based on results from an excellent recent technical trial. The best drones can detect almost all methane leaks >90% faster than traditional methods.
Companies developing next-generation methane-mitigation technologies are screened, including 10 public companies and 33 private companies. This peer group filed 150 patents in 2018-19. 8 companies seem particularly exciting to us.
Operators are also screened, across the dozen largest Energy Majors, to estimate their methane leaks and broader methane intensity across the supply chain.
This short model calculates the impact of methane emissions on the CO2/boe of burning natural gas, compared against coal. With methane emissions fully controlled, burning gas is c60% lower-CO2 than burning coal.
However, taking natural gas to cause 120x more warming than CO2 over an immediate timeframe, the crossover (where coal emissions and gas emissions are equivalent) is 4% methane intensity. i.e., if 4-20% of methane is leaked, then the total warming from burning natural gas is equivalent to coal’s.
Gas gathering and gas processing are 50% less CO2 intensive than oil refining. Nevertheless, these processes emitted 18kg of CO2e per boe in 2018, hence the gas industry must strive to improve.
Methane matters most, explaining 7kg/boe of the gas industry’s CO2-equivalents, via leaks and fugitive emissions (and this is with 1 kg of methane translated into 25 kg of CO2e). Hence US methane intensity ran at c0.5% in 2018.
The numbers vary widely by geography and by operator, and are quantified in this data-file, after analysing 850 facilities’ EPA disclosures. Very detailed and comparable disclosures are broken out for US gas gathering, to screen for leaders and laggards.
Covered companies include Antero, BP, Denbury, DCP, DTE, Equinor, Equitrans, Energy Transfer Partners, Enlink, Enterprise Product Partners, EOG, ExxonMobil, Kinder Morgan, Oneok, Pioneer, Shell, Targa, Williams.
Lower carbon oil and gas may be increasingly valued by investors, earning higher multiples and lower costs of capital. This is the conclusion from our recent investor survey, linked here.
c80% now find it harder to invest in oil and gas, because of the need to decarbonise energy. However, 90% see lower carbon barrels as part of the solution. Hence 80% stated that lower capital costs could be warranted for these lower carbon producers.
Higher carbon barrels are currently being punished with c6% higher costs of capital, on average, compared with more typical projects. However, lower carbon barrels are not yet being rewarded, ascribed just 2% lower costs of capital, according to the survey data.
We will be happy to send a free copy of the data-file to all those that complete the survey, otherwise, it can be purchased below.
What if it were possible to displace diesel from high-cost, high-carbon “island” electricity grids, by charging up large batteries with gas- and renewable power, then shipping the batteries?
This model assesses the relative economics and relative CO2 emissions of such a possibility. The model is sensitive to oil prices, battery prices, hurdle rates and alternative power prices.
Economics should improve as battery prices fall. But costs are already competitive for several island grids, while CO2 intensity can be halved. Our numbers have been informed by disclosures from Gridspan Energy, a leading company in this space.
This data-file provides an overview of eleven different processes for commercial hydrogen production: including their energy-economics, costs and CO2 emissions; plus a qualitative description of their opportunities, challenges and technical readiness.
Covered technologies include steam methane reforming, fossil fuel gasification, pyrolysis, renewable electrolysis, fuel cell electrolysis, solar photoelectrocatalysis and solar photocatalysis.
Our conclusion is that natural gas remains the most viable fuel source on a weighted basis, considering both cost and carbon emissions, It may also be easier to de-carbonise natural gas directly than via the hydrogen route.