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.
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 fuelin 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.
We have constructed a simple model to estimate the CO2 emissions of commercialising a gas resource, as a function of eight input variables: such as production techniques, methane leakage, sour gas processing, LNG liquefaction, LNG tanker distances and pipeline distances.
We estimate energy return on energy invested is c25-30x across piped gas resources and c15x across LNG resources, compared with c7-10x for oil. This supports the rationale for oil-to-gas switching, as commercialising gas will likely emit 50-75% lower CO2 per boe.
Different resources are compared using our methodology. The lowest CO2 profile is seen for well-managed piped gas (e.g., Norway to Europe).
Download the modeland you can quickly compute approximate CO2 emissions for other resources.
This data-file summarises six leading CO2-separation technologies. For each one, we outline the process, its technical maturity, costs, CO2-selectivity, energy-intensity and drawbacks. Our notes and workings are also included in subsequent tabs.
A $50/ton carbon price would be neededto incentivise more CCS, using today’s conventional, technically mature methods. The problem remains, that these means suffer from energy penalties of 15-30%.
Metal Organic Frameworkscould be a material breakthrough, with c60-80% lower costs and energy penalties. These remarkable materials can contain 10,000m2 of surface area in a single gram, with impressive tuning to adsorb specific gases. Our file contains new notes on MOFs, including the technology leaders: 4 listed companies, 5 start-ups and 225 patents from 2018-19.
This is a simple model of long-term LNG demand, extrapolating out sensible estimates in the world’s leading LNG-consuming regions. On top of this, we overlay the upside from two nascent technology areas, which could add 200MTpa of potential upside to the market. Backup workings are included.
Our LNG supply model looks project-by-project, across 115 LNG facilites: including c40 mature plants, c15 under development, c20 in design and c30 under discussion.
Our base case supply estimatescome from “risking” the supply associated with each of these projects (chart below).
The outlook depends on the path. The 2030 supply outlook can vary by 250MTpa, when comparing all reasonably possible supply (top chart) against the firm supply-growth that looks all but locked (bottom chart).
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.
We have reviewed 42 of Shell’s GTL patent filings for 2018. They show continued progress, innovating new fuels, lubricants, renewable-heavy gasolines, waxes and detergents. Each patent is summarised and categorized in this data-file.
All of this begs the question whether there is a commercial rationale for a US replica of the Pearl GTL project, to handle the over-abundance of gas emanating from the Permian; and produce these advantaged products. It would also help reduce the risk of US LNG projects glutting the market.
We therefore model the economicsin this data-file, using prior project disclosures and our learnings from the patent history. Our base case IRR is 15%, taking in 1.6bcfd of shale gas. Resiliency is tested by varying oil and gas prices.
This data-file compares different trucking fuels— diesel, CNG, LNG, LPG and Hydrogen — across 35 variables. Most important are the economics, which are fully modelled.
Natural Gas can be close to competitive. On an energy-equivalent basis, $3/mcf gas is 4x more economical than $3/gal diesel. However, the advantages are offset by higher vehicle costs, operational costs and logistical costs. Overall, CNG ends up 10% more expensive, and LNG ends up 30% more expensive versus diesel-trucking. Mild environmental positives of gas are also offset by mild operational challenges.
Hydrogen still screens as an expensive alternative. We estimate vehicle costs are 2x higher than diesel trucks, while $15/kg hydrogen is 4x more expensive than diesel as a fuel.
For large-scale capital projects in a commodity industry, harnessing better technologies tends to unlock better returns.
Hence this 7-page note evaluates ExxonMobil’s technology for constructing greenfield LNG plants, particularly in remote geographies. Its technical leadership stands out from our analysis of 3,000 patents across the industry. This matters as Exxon progresses new LNG investments in Mozambique, PNG and the US.
ExxonMobil has leading LNG technologyfor extra-large trains using the APX process, modular LNG units that minimise on-site construction costs, pressure-swing absorption to remove gas-contaminants and efficient gas turbines.
Opportunities should arisefor investors in Exxon’s LNG projects, and for its partners, resource-owners and other stakeholders, to ensure that value is maximised.
China’s future gas production, and thus its need for LNG imports, depends heavily on its prospects in shale: Technically recoverable resources have been assessed at a vast 31.6TCM by the EIA.
But >50% shortfalls are looming against the 2016 target to produce 30bcm by 2020. Production ran at just 11bcm last year. And many Majors have now exited. So what are the main challenges, hindering development?
In order to answer this question, we have summarised ten recent technical paper on the Chinese shale gas industry.
This data-file tabulates the most-cited challenges, and the solutions that are suggested to combat them. It also includes our “top ten conclusions” on Chinese shale gas.