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.
This model contains our live, basin-by-basin shale forecasts. It covers the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rates, well productivity and type curves. Thus, we derive production and financial expectations.
For 2022, the key challenge is stepping up activity levels, as the rig count must rise +60% YoY to keep early-2020s oil markets sufficiently supplied. Conversely, in 2021, production surpassed our expectations due to an unprecedented rate of DUC drawdowns, while well productivity was also stronger-than-feared.
Our longer-term numbers hinge on the productivity gainsdescribed in our thematic research. Shale productivity trebled from 2012-2018. We think it can rise another 45% by 2025, unlocking 15Mbpd of liquid shale production. However productivity could disappoint mildly in 2022 as the industry ramps activity levels back post-COVID.
We have also modeled the Marcellus shale gas play, using the same framework, in a further tab of the data-file. Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion here, with 20-50 additional rigs.
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 barrelsare 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.
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 estimatescan be flexed in the ‘simple model’ tab. Underlying cost calculations are substantiated in the ‘Notes’ tab.
We have modelled the economics of CO2-EOR in shale, after interest in this topic spiked 2.3x YoY in the 2019 technical literature. Our deep-dive research into the topic is linked here.
The economics appear positive, with a 15% IRR under our base case assumptions, and very plausible upside to 25-30%.
There is potential to sequester 3.5bn tons of CO2 in shale formations in the US, plus another 40bn tons internationally, for a CO2 disposal fee of c$40/ton, which we have quantified based on the technical literature.
The model also allows you to stress-test your own assumptions such as: oil prices, gas prices, CO2 prices, CO2 tax-credits, compressor costs and productivity uplift. The impacts on IRR, NPV and FCF are visible.
Equinor is deploying three world-class technologies to mitigate Johan Sverdrup’s decline rates, based on reviewing c115 of the company’s patents and dozens of technical papers. This 15-page note outlines how its efforts may unlock an incremental $3-5bn of value from the field, as production surprises to the upside.
We have modelled the economics of Equinor’s Johan Sverdrup oilfield, using public disclosures and own estimates. Our model spans >250 lines of inputs and outputs, so you can flex key assumptions, such as oil prices, gas prices, production profiles and costs. In particular, we have tested the impact of different decline rates and recovery factors on the field’s ultimate value.
This data-file quantifies the impact that technology can have on offshore economics. We start with a 250-line field model, for a typical offshore oil and gas project. We then list our “top twenty” offshore technologies, which can improve the economics. In a third tab, we update our base case model, line-by-line, to reflect these twenty technologies. Finally, the “before” and the “after” are compared and contrasted.
This data-file tabulates the approximate cash flow, capex and ‘pre-tax costs’ of Oil Majors, in order to illustrate the operational leverage within the group. Every $1 of free cash flow comes after $3 of cost. Hence small reductions in the cost base, through technology, deliver 3x larger uplifts to free cash flow. This is why we are screening Oil companies’ technology-capabilities.
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