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-monitoring technologies are screened, including 12 private companies in growth mode, 8 private companies advancing new technologies and 6 public companies.
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 25x more warming than CO2 over a 120-year timeframe, the crossover (where coal emissions and gas emissions are equivalent) is 7% methane intensity. Taking natural gas to cause 120x more warming than CO2 over an immediate timeframe, the crossover is 1.5%.
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.
This data-file tabulates global flaring intensity in 16 countries of interest: in absolute terms (bcm per year), per barrel of oil production (mcf/bbl) and as a contribution to CO2 emissions (kg/boe).
Flaring intensity has reduced by c20% in the past quarter-century, from 0.25mcf/bbl and 12.5kg of CO2/bbl in the early 1990s to 0.2mcf/bbl and 10kg/bbl today. However, total flaring nevertheless increased by c13% in absolute terms, accounting for 350MTpa of global CO2 emissions. This is 1/6th of total oil industry CO2.
Industry leaders, with the lowest flaring include Saudi Arabia and the US. Laggards include West Africa, North Africa, Iran/Iraq and Venezuela (which has shown the worst deterioration in the database, since the late 1990s).
LNG’s positive role in reducing flaring stands out from the data. LNG exports were 94% correlated with Nigeria’s flaring reduction since NLNG started up in 1999. Angola has also reduced flaring by 80% since 1998, with Angola LNG “starting up” in 2013. Finally, Equatorial Guinea now has 80% lower flaring than its neighbor, Gabon, since starting up EGLNG in 2007.
This data-file breaks down global CO2 emissions into 35 distinct categories, based on prior publications, our own models and calculations.
The long tail illustrates the complexity of decarbonisation. The largest single component of global emissions is passenger vehicles, but this comprises just c14% of the total CO2e.
A further 30 line-items all account for at least 1% of the world’s total emissions including electricity, heating, cement, metals, plastics, food, fertilizers, paper, manufacturing, livestock, agriculture, military, oil refining, fossil fuel production and landfill.
Large LNG projects make large headlines. But we are excited by the ascent of smaller-scale LNG. At <1MTpa each, these facilities can be harder to track, which is the objective of this data-file.
There is currently c13MTpa of small-scale LNG liquefaction capacity online, across 70 facilities, of which c50 are in China and c10 in the US. A further c12MTpa pipeline is in progress, for a 100% increase.
We estimate small-scale LNG supplied c0.2MTpa of shipping fuel in 2017, compared to c260MT of total liquid shipping fuels. Dedicated LNG shipping fuels capacity should rise 20x, to 4MTpa by the end of 2021; and total shipping fuels could reach 40MTpa by 2040.
Exciting projects are currently ramping up: in Russia, Novatek’s Vyotsk (1.1MTpa) and Gazprom’s Portovaya are both devoted to Baltic shipping fuels (1.5MTpa) and sourced from the same input gas as Nord Stream; followed in the US Gulf, by Florida’s Eagle LNG (0.9MTpa) and in Louisiana.
Small-scale LNG growth is particularly exciting around European markets, where by 2022 there will be 5x more port-side facilities than a decade prior.
For all the underlying data, please download this data-file. For our research on this theme, please see the note, ‘LNG in transport: scaling up by scaling down’.
